Edgar Filing: WPS RESOURCES CORP

Form 10-Q 9/30/05

______________________________________________________________________________

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________

Commission File Number	Registrants; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.

1-11337	WPS RESOURCES CORPORATION (A Wisconsin Corporation) 700 North Adams Street P. O. Box 19001 Green Bay, WI 54307-9001 920-433-4901	39-1775292

1-3016	WISCONSIN PUBLIC SERVICE CORPORATION (A Wisconsin Corporation) 700 North Adams Street P. O. Box 19001 Green Bay, WI 54307-9001 800-450-7260	39-0715160

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

WPS Resources Corporation	Yes [x] No [ ]
Wisconsin Public Service Corporation	Yes [x] No [ ]

Indicate by check mark whether the registrants are accelerated filers (as defined in Rule 12b-2 of the Exchange Act).

WPS Resources Corporation	Yes [x] No [ ]
Wisconsin Public Service Corporation	Yes [ ] No [x ]

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

WPS Resources Corporation	Yes [ ] No [x ]
Wisconsin Public Service Corporation	Yes [ ] No [x ]

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:

WPS RESOURCES CORPORATION	Common stock, $1 par value, 38,094,761 shares outstanding at October 31, 2005

WISCONSIN PUBLIC SERVICE CORPORATION	Common stock, $4 par value, 23,896,962 shares outstanding at October 31, 2005

______________________________________________________________________________

WPS RESOURCES CORPORATION AND WISCONSIN PUBLIC SERVICE CORPORATION FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2005 CONTENTS
		Page

	FORWARD-LOOKING STATEMENTS	4

PART I.	FINANCIAL INFORMATION

Item 1.	FINANCIAL STATEMENTS
	WPS RESOURCES CORPORATION
	Consolidated Statements of Income	5
	Consolidated Balance Sheets	6
	Consolidated Statements of Cash Flows	7

	WISCONSIN PUBLIC SERVICE CORPORATION
	Consolidated Statements of Income	8
	Consolidated Balance Sheets	9
	Consolidated Statements of Capitalization	10
	Consolidated Statements of Cash Flows	11

	CONDENSED NOTES TO FINANCIAL STATEMENTS OF
	WPS Resources Corporation and Subsidiaries Wisconsin Public Service Corporation and Subsidiaries	12-35

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations for
	WPS Resources Corporation	36-70
	Wisconsin Public Service Corporation	71-80

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	81

Item 4.	Controls and Procedures	82

PART II.	OTHER INFORMATION	83

Item 1.	Legal Proceedings	83

Item 5.	Other Information	83

Item 6.	Exhibits	84

Signatures		85-86


	CONTENTS (continue)	Page

EXHIBIT INDEX		87

12.1	WPS Resources Corporation Ratio of Earnings to Fixed Charges
12.2	Wisconsin Public Service Corporation Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources Corporation
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources Corporation
31.3	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation
31.4	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation
32.1	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPS Resources Corporation
32.2	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Wisconsin Public Service Corporation

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Commonly Used Acronyms
ATC	American Transmission Company LLC
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
ESI	WPS Energy Services, Inc.
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
MISO	Midwest Independent System Operator
MPSC	Michigan Public Service Commission
PDI	WPS Power Development, LLC
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
UPPCO	Upper Peninsula Power Company
WDNR	Wisconsin Department of Natural Resources
WPSC	Wisconsin Public Service Corporation

-3-

Forward-Looking Statements

Except for historical data and statements of current fact, the information contained or incorporated by reference in this document constitutes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Any references to plans, goals, beliefs or expectations in respect to future events and conditions or to estimates are forward-looking statements. Although we believe that statements of our expectations are based on reasonable assumptions, forward-looking statements are inherently uncertain and subject to risks and should be viewed with caution. Actual results or experience could differ materially from the forward-looking statements as a result of many factors.

In addition to statements regarding trends or estimates in Management's Discussion and Analysis of Financial Condition and Results of Operations, forward-looking statements included or incorporated in this report include, but are not limited to, statements regarding future:

·	Revenues or expenses,

·	Capital expenditure projections, and

·	Financing sources.

Forward-looking statements involve a number of risks and uncertainties. There are many factors that could cause actual results to differ materially from those expressed or implied in this report. Some of those factors include:

·	Receipt of required regulatory approvals for the acquisition of the Michigan and Minnesota natural gas distribution operations from Aquila;

·	Resolution of pending and future rate cases and negotiations (including the recovery of deferred costs) and other regulatory decisions regarding WPSC and UPPCO;

The impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, changes in environmental, tax and other laws and regulations to which WPS Resources and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

·	Current and future litigation, regulatory investigations, proceedings or inquiries, including manufactured gas plant site cleanup and pending EPA investigations of WPSC generation facilities;

·	Resolution of audits by the Internal Revenue Service and various state revenue agencies;

·	The effects, extent and timing of additional competition in the markets in which WPS Resources' subsidiaries operate;

·	The impact of fluctuations in commodity prices, interest rates and customer demand;

·	Available sources and costs of fuels and purchased power;

·	Ability to control costs (including costs of decommissioning generation facilities);

·	Investment performance of employee benefit plans;

·	Advances in technology;

·	Effects of and changes in political, legal and economic conditions and developments in the United States and Canada;

·	The performance of projects undertaken by nonregulated businesses and the success of efforts to invest in and develop new opportunities;

Potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed (such as acquisition of the Michigan and Minnesota natural gas distribution operations from Aquila, construction of the Weston 4 generation plant and construction of the Wausau, Wisconsin to Duluth, Minnesota transmission line);

·	The direct or indirect effect resulting from terrorist incidents or responses to such incidents;

·	Financial market conditions and the results of financing efforts, including credit ratings and risks associated with commodity prices, interest rates and counterparty credit;

·	Weather and other natural phenomena; and

·	The effect of accounting pronouncements issued periodically by standard-setting bodies.

Except to the extent required by the federal securities laws, WPS Resources and its subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this report.

-4-


PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

WPS RESOURCES CORPORATION


CONDENSED CONSOLIDATED STATEMENTS OF INCOME	Three Months Ended						Nine Months Ended
(Unaudited)	September 30						September 30
(Millions, except per share amounts)	2005			2004			2005			2004

Nonregulated revenue	$	1,396.0		$	812.8		$	3,478.1		$	2,596.8
Utility revenue		361.3			279.1			1,093.6			941.6
Total revenues		1,757.3			1,091.9			4,571.7			3,538.4

Nonregulated cost of fuel, gas, and purchased power		1,335.2			784.5			3,324.2			2,499.9
Utility cost of fuel, gas, and purchased power		190.5			97.3			526.8			404.9
Operating and maintenance expense		124.0			123.9			399.4			394.1
Depreciation and decommissioning expense		23.8			26.1			119.6			78.4
Gain on sale of emission allowances		-			-			(86.8	)		-
Impairment loss		-			-			80.6			-
Taxes other than income		11.8			11.5			35.7			34.8
Operating income		72.0			48.6			172.2			126.3

Miscellaneous income		9.6			9.9			62.8			20.8
Interest expense		(15.6	)		(14.9	)		(56.2	)		(44.2	)
Minority interest		1.2			1.2			3.4			2.3
Other income (expense)		(4.8	)		(3.8	)		10.0			(21.1	)

Income before taxes		67.2			44.8			182.2			105.2
Provision for income taxes		18.3			9.3			41.9			20.9
Net income before preferred stock dividends of subsidiary		48.9			35.5			140.3			84.3

Preferred stock dividends of subsidiary		0.7			0.7			2.3			2.3
Income available for common shareholders	$	48.2		$	34.8		$	138.0		$	82.0


Average shares of common stock
Basic		38.2			37.4			38.0			37.2
Diluted		38.6			37.6			38.3			37.5

Earnings per common share
Basic	$	1.26		$	0.93		$	3.63		$	2.20
Diluted	$	1.25		$	0.93		$	3.60		$	2.19

Dividends per common share declared	$	0.565		$	0.555		$	1.675		$	1.645

The accompanying condensed notes are an integral part of these statements.

-5-


WPS RESOURCES CORPORATION


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	September 30		December 31
(Millions)	2005		2004

Assets
Cash and cash equivalents	$	27.4	$	40.0
Accounts receivable - net of reserves of $9.4 and $8.0, respectively		796.6		531.3
Accrued unbilled revenues		71.2		113.2
Inventories		272.9		196.1
Current assets from risk management activities		1,355.9		376.5
Assets held for sale		0.8		24.1
Other current assets		70.9		91.5
Current assets		2,595.7		1,372.7

Property, plant, and equipment, net of reserves of $1,097.9 and $1,588.5, respectively		2,056.0		2,076.5
Nuclear decommissioning trusts		-		344.5
Regulatory assets		234.7		160.9
Long-term assets from risk management activities		241.0		74.6
Other		351.1		347.6
Total assets	$	5,478.5	$	4,376.8

Liabilities and Shareholders' Equity
Short-term debt	$	148.0	$	292.4
Current portion of long-term debt		3.7		6.7
Accounts payable		851.2		589.4
Current liabilities from risk management activities		1,364.0		338.6
Deferred income taxes		4.4		9.1
Other current liabilities		153.4		73.2
Current liabilities		2,524.7		1,309.4

Long-term debt		869.6		865.7
Deferred income taxes		18.6		71.0
Deferred investment tax credits		15.1		16.2
Regulatory liabilities		379.3		288.3
Environmental remediation liabilities		66.9		68.4
Pension and postretirement benefit obligations		77.5		94.6
Long-term liabilities from risk management activities		197.8		62.5
Asset retirement obligations		2.8		366.6
Other		109.7		91.2
Long-term liabilities		1,737.3		1,924.5

Commitments and contingencies

Preferred stock of subsidiary with no mandatory redemption		51.1		51.1
Common stock equity		1,165.4		1,091.8
Total liabilities and shareholders' equity	$	5,478.5	$	4,376.8

The accompanying condensed notes are an integral part of these statements.

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WPS RESOURCES CORPORATION


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(Millions)	2005			2004
Operating Activities
Net income before preferred stock dividends of subsidiary	$	140.3		$	84.3
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and decommissioning		119.6			78.4
Amortization of nuclear fuel and other		43.0			35.2
Realized gain on investments held in trust, net of regulatory deferral		(15.7	)		(3.3	)
Pension and postretirement expense		37.8			30.4
Pension and postretirement funding		(8.2	)		-
Deferred income taxes and investment tax credit		(41.3	)		9.2
Unrealized gains on nonregulated energy contracts		(22.0	)		-
Gain on sale of partial interest in synthetic fuel operation		(5.5	)		(5.6	)
Gain on sale of emission allowances		(86.8	)		-
Impairment loss		80.6			-
Deferral of Kewaunee outage costs		(57.8	)		-
Other		(31.8	)		(20.8	)
Changes in working capital
Receivables, net		(231.8	)		137.6
Inventories		(52.4	)		(15.1	)
Other current assets		6.4			(0.1	)
Accounts payable		258.0			(57.5	)
Other current liabilities		40.0			(13.4	)
Net cash provided by operating activities		172.4			259.3

Investing Activities
Capital expenditures		(293.7	)		(199.4	)
Sale of property, plant and equipment		3.8			4.7
Sale of emission allowances		110.9			-
Purchase of equity investments and other acquisitions		(48.5	)		(37.5	)
Proceeds from sale of Kewaunee power plant		112.5			-
Proceeds from liquidation of non-qualified decommissioning trust		127.1			-
Other		(1.0	)		22.3
Net cash provided by (used for) investing activities		11.1			(209.9	)

Financing Activities
Short-term debt - net		(141.8	)		102.4
Repayment of long-term debt and note to preferred stock trust		(1.9	)		(105.7	)
Payment of dividends
Preferred stock		(2.3	)		(2.3	)
Common stock		(63.0	)		(60.9	)
Issuance of common stock		23.7			22.3
Other		(10.8	)		(0.8	)
Net cash used for financing activities		(196.1	)		(45.0	)
Change in cash and cash equivalents		(12.6	)		4.4

Cash and cash equivalents at beginning of period		40.0			50.7
Cash and cash equivalents at end of period	$	27.4		$	55.1

The accompanying condensed notes are an integral part of these statements

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WISCONSIN PUBLIC SERVICE CORPORATION


CONDENSED CONSOLIDATED STATEMENTS OF INCOME	Three Months Ended						Nine Months Ended
(Unaudited)	September 30						September 30
(Millions)	2005			2004			2005			2004

Operating revenues
Electric	$	266.7		$	214.6		$	705.8		$	603.2
Gas		71.8			45.6			336.2			288.8
Total operating revenues		338.5			260.2			1,042.0			892.0
Operating expenses
Electric production fuels		55.7			35.5			142.1			102.6
Purchased power		75.2			26.7			127.3			80.9
Gas purchased for resale		52.6			28.8			247.1			203.4
Other operating expenses		68.7			72.1			230.5			226.8
Maintenance		13.4			16.7			50.6			56.8
Depreciation and decommissioning		19.7			21.9			107.0			66.7
Federal income taxes		8.6			11.5			23.7			30.5
Investment tax credit restored		(0.3	)		(0.3	)		(1.0	)		(1.0	)
State income taxes		4.2			3.5			7.2			8.6
Gross receipts tax and other		9.7			9.4			29.7			28.8
Total operating expense		307.5			225.8			964.2			804.1
Operating income		31.0			34.4			77.8			87.9
Other income and (deductions)
Allowance for equity funds used during construction		0.4			0.5			1.3			1.5
Other, net		3.6			5.9			51.2			14.9
Income taxes		0.1			(1.2	)		(16.8	)		(2.2	)
Total other income		4.1			5.2			35.7			14.2
Interest expense
Interest on long-term debt		7.4			7.4			22.4			22.4
Other interest		1.4			1.2			4.6			3.0
Allowance for borrowed funds used during construction		(0.1	)		(0.2	)		(0.4	)		(0.5	)
Total interest expense		8.7			8.4			26.6			24.9
Net income		26.4			31.2			86.9			77.2
Preferred stock dividend requirements		0.7			0.7			2.3			2.3
Earnings on common stock	$	25.7		$	30.5		$	84.6		$	74.9


The accompanying condensed notes are an integral part of these statements.

-8-

WISCONSIN PUBLIC SERVICE CORPORATION


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	September 30		December 31
(Millions)	2005		2004
ASSETS

Utility plant
Electric	$	1,869.2	$	2,223.9
Gas		530.9		510.0
Total		2,400.1		2,733.9
Less - Accumulated depreciation		973.2		1,189.3
Total		1,426.9		1,544.6
Nuclear decommissioning trusts		-		344.5
Construction in progress		351.2		153.1
Nuclear fuel, less accumulated amortization		-		24.6
Net utility plant		1,778.1		2,066.8

Current assets
Cash and cash equivalents		4.0		3.5
Customer and other receivables, net of reserves of $6.1 at September 30, 2005
and $5.5 at December 31, 2004		109.1		106.2
Receivables from related parties		13.9		9.1
Accrued unbilled revenues		35.4		68.4
Fossil fuel, at average cost		21.2		15.2
Gas in storage, at average cost		78.0		60.2
Materials and supplies, at average cost		23.0		28.3
Assets from risk management activities		46.2		5.7
Prepayments and other		23.7		39.3
Total current assets		354.5		335.9

Regulatory assets		230.2		156.5
Goodwill		36.4		36.4
Investments and other assets		149.9		173.0
Total assets	$	2,549.1	$	2,768.6


CAPITALIZATION AND LIABILITIES

Capitalization
Common stock equity	$	957.0	$	899.7
Preferred stock with no mandatory redemption		51.2		51.2
Long-term debt to parent		11.6		12.0
Long-term debt		496.1		496.0
Total capitalization		1,515.9		1,458.9

Current liabilities
Short-term debt		42.0		101.0
Accounts payable		160.0		145.1
Payables to related parties		10.4		8.9
Accrued interest and taxes		11.7		8.1
Other		72.9		20.5
Total current liabilities		297.0		283.6

Long-term liabilities and deferred credits
Accumulated deferred income taxes		112.3		130.1
Accumulated deferred investment tax credits		14.2		15.2
Regulatory liabilities		360.5		271.1
Environmental remediation liability		65.3		66.7
Pension and postretirement benefit obligations		75.9		92.9
Asset retirement obligations		0.4		364.4
Payables to related parties		16.8		18.6
Other long-term liabilities		90.8		67.1
Total long-term liabilities and deferred credits		736.2		1,026.1

Commitments and contingencies		-		-
Total capitalization and liabilities	$	2,549.1	$	2,768.6


The accompanying condensed notes are an integral part of these statements.

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WISCONSIN PUBLIC SERVICE CORPORATION


CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION (Unaudited)	September 30			December 31
(Millions, except share amounts)	2005			2004

Common stock equity
Common stock	$	95.6		$	95.6
Premium on capital stock		549.7			516.0
Accumulated other comprehensive loss		(20.7	)		(20.7	)
Retained earnings		332.4			308.8
Total common stock equity		957.0			899.7

Preferred stock
Cumulative, $100 par value, 1,000,000 shares authorized
with no mandatory redemption -

Series Shares Outstanding
5.00% 131,916		13.2			13.2
5.04% 29,983		3.0			3.0
5.08% 49,983		5.0			5.0
6.76% 150,000		15.0			15.0
6.88% 150,000		15.0			15.0
Total preferred stock		51.2			51.2

Long-term debt to parent
Series Year Due
8.76% 2015		4.8			5.0
7.35% 2016		6.8			7.0
Total long-term debt to parent		11.6			12.0

Long-term debt
First mortgage bonds
Series Year Due
6.90% 2013		22.0			22.0
7.125% 2023		0.1			0.1
Senior notes
Series Year Due
6.125% 2011		150.0			150.0
4.875% 2012		150.0			150.0
4.8% 2013		125.0			125.0
6.08% 2028		50.0			50.0
Total		497.1			497.1
Unamortized discount and premium on bonds, net		(1.0	)		(1.1	)
Total long-term debt		496.1			496.0
Total capitalization	$	1,515.9		$	1,458.9


The accompanying condensed notes are an integral part of these statements.

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WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(Millions)	2005			2004

Operating Activities
Net income	$	86.9		$	77.2
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and decommissioning		107.0			66.7
Amortization		30.1			29.4
Deferred income taxes		(20.8	)		12.8
Investment tax credit restored		(1.0	)		(1.0	)
Allowance for funds used during construction		(1.7	)		(1.5	)
Realized gain on investments		(15.7	)		(3.3	)
Equity income		(8.4	)		(10.7	)
Pension and post retirement expense		29.0			22.0
Pension and post retirement funding		(8.2	)		-
Deferral of Kewaunee outage expenses		(57.8	)		-
Other		(21.6	)		(6.0	)
Changes in -
Customer and other receivables		(22.0	)		15.3
Accrued utility revenues		33.0			24.6
Fossil fuel inventory		(5.4	)		(0.8	)
Gas in storage		(17.8	)		(16.4	)
Miscellaneous assets		15.5			(3.7	)
Accounts payable		6.8			(2.2	)
Accrued taxes and interest		4.3			(0.3	)
Miscellaneous current and accrued liabilities		3.8			3.6
Net cash provided by operating activities		136.0			205.7

Investing Activities
Capital expenditures		(283.9	)		(185.4	)
Proceeds from the sale of Kewaunee power plant		112.5			-
Proceeds from the liquidation of non-qualified decommissioning trust		127.1			-
Other		(0.3	)		16.4
Net cash used for investing activities		(44.6	)		(169.0	)

Financing Activities
Short-term debt - net		(59.0	)		31.0
Payments of long-term debt		(0.3	)		(50.2	)
Net equity contributions from parent		30.0			40.0
Dividends to parent		(60.8	)		(56.3	)
Preferred stock dividends		(2.3	)		(2.3	)
Other		1.5			1.7
Net cash used for financing activities		(90.9	)		(36.1	)
Change in cash and cash equivalents		0.5			0.6
Cash and cash equivalents at beginning of period		3.5			4.7
Cash and cash equivalents at end of period	$	4.0		$	5.3


The accompanying condensed notes are an integral part of these statements.

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WPS RESOURCES CORPORATION AND SUBSIDIARIES

WISCONSIN PUBLIC SERVICE CORPORATION AND SUBSIDIARY

CONDENSED NOTES TO FINANCIAL STATEMENTS

September 30, 2005

NOTE 1--FINANCIAL INFORMATION

We have prepared the condensed consolidated financial statements of WPS Resources and WPSC under the rules and regulations of the SEC. These financial statements have not been audited. Management believes that these financial statements include all adjustments (which unless otherwise noted include only normal recurring adjustments) necessary for a fair presentation of the financial results for each period shown. Certain items from the prior period have been reclassified to conform to the current year presentation. We have condensed or omitted certain financial information and footnote disclosures normally included in our annual audited financial statements. These financial statements should be read along with the audited financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2004, and along with the revised financial statements and related disclosures included in the Current Report on Form 8-K dated August 25, 2005 (filed with the SEC on August 26, 2005).

For all periods presented, certain assets and liabilities of Sunbury have been reclassified as held and used and Sunbury's results of operations and cash flows have been reclassified into continuing operations. See Note 4, Assets Held for Sale, for more information.

NOTE 2--CASH AND CASH EQUIVALENTS

We consider short-term investments with an original maturity of three months or less to be cash equivalents.

The following is supplemental disclosure to the WPS Resources and WPSC Condensed Consolidated Statements of Cash Flows:


(Millions)	Nine Months Ended September 30
WPS Resources	2005		2004
Cash paid for interest	$	38.9	$	34.1
Cash paid for income taxes		47.4		26.7

WPSC
Cash paid for interest	$	21.1	$	19.9
Cash paid for income taxes		39.5		25.3

During the nine months ended September 30, 2005, accounts payable related to Weston 4 construction costs increased approximately $23.6 million, and accordingly, are treated as non-cash investing activities. Weston 4 construction costs funded through accounts payable were not significant during the nine months ended September 30, 2004.

NOTE 3--RISK MANAGEMENT ACTIVITIES

As part of our regular operations, WPS Resources enters into contracts, including options, swaps, futures, forwards, and other contractual commitments, to manage market risks such as changes in commodity prices and interest rates.

WPS Resources accounts for its derivative contracts in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended and interpreted. SFAS No. 133 establishes accounting and financial reporting standards for derivative instruments and requires, in part, that we recognize certain derivative instruments on the balance sheet as assets or liabilities at their fair value. Subsequent changes in fair value of the derivatives are recorded currently in earnings unless certain

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hedge accounting criteria are met. If the derivatives qualify for regulatory deferral subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," the derivatives are marked to fair value pursuant to SFAS No. 133 and are offset with a corresponding regulatory asset or liability.

The following table shows WPS Resources’ assets and liabilities from risk management activities:


	Assets				Liabilities
(Millions)	September 30, 2005		December 31, 2004		September 30, 2005		December 31, 2004
Utility Segment
Natural gas and electric purchase contracts	$	31.6	$	11.0	$	-	$	-
Financial transmission rights		25.6		-		3.5		0.6
Nonregulated Segments
Commodity and foreign currency contracts		1,450.7		396.5		1,387.1		366.6
Fair value hedges		4.9		3.8		32.8		2.3
Cash flow hedges
Commodity contracts		84.1		39.8		132.9		22.9
Interest rate swaps		-		-		5.5		8.7
Total	$	1,596.9	$	451.1	$	1,561.8	$	401.1
Balance Sheet Presentation
Current	$	1,355.9	$	376.5	$	1,364.0	$	338.6
Long-Term		241.0		74.6		197.8		62.5
Total	$	1,596.9	$	451.1	$	1,561.8	$	401.1

Assets and liabilities from risk management activities are classified as current or long-term based upon the maturities of the underlying financial instruments.

Utility Segment

WPSC has entered into a limited number of natural gas and electric purchase contracts that are accounted for as derivatives and shown in the above table. In addition, "Financial transmission rights" includes financial instruments used to manage the transmission congestion costs of the electric utility. The PSCW approved the recognition of a regulatory asset or liability for the fair value of derivative amounts. Thus, management believes any gains or losses resulting from the eventual expiration or settlement of these derivative instruments will be collected from or refunded to customers.

Nonregulated Segments

The derivatives in the nonregulated segments not designated as hedges under generally accepted accounting principles are primarily commodity contracts used to manage price risk associated with natural gas purchase and sale activities, electric energy contracts, and foreign currency contracts used to manage foreign currency exposure related to our nonregulated Canadian businesses. In addition, PDI entered into a series of derivative contracts (options) covering a specified number of barrels of oil in order to manage exposure to the risk of an increase in oil prices that could reduce the amount of Section 29 federal tax credits that can be recognized from PDI's investment in a synthetic fuel production facility for 2005-2007. See Note 11, Commitments and Contingencies, for more information. Changes in the fair value of non-hedge derivatives are recognized currently in earnings.

Our nonregulated segments also enter into derivative contracts that are designated as either fair value or cash flow hedges. Fair value hedges are used to mitigate the risk of changes in the price of natural gas held in storage. The changes in the fair value of these hedges are recognized currently in earnings, as are the changes in fair value of the hedged items. Fair value hedge ineffectiveness recorded in nonregulated revenue on the Condensed Consolidated Statements of Income was not significant for the

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nine months ended September 30, 2005, and 2004. At September 30, 2005, a pre-tax mark-to-market loss of $5.1 million related to changes in the difference between the spot and forward prices of natural gas was excluded from the assessment of hedge effectiveness. This loss was reported directly in earnings. The amount excluded from the assessment of hedge effectiveness at December 31, 2004, was not significant.

Commodity contracts that are designated as cash flow hedges extend through October 2007 and are used to mitigate the risk of cash flow variability associated with the future purchases and sales of natural gas and electricity. To the extent they are effective, the changes in the values of these contracts are included in other comprehensive income, net of deferred taxes. Cash flow hedge ineffectiveness recorded in nonregulated revenue on the Condensed Consolidated Statements of Income related to commodity contracts was not significant for the nine months ended September 30, 2005, and 2004. When testing for effectiveness, no portion of the derivative instruments was excluded. Amounts recorded in other comprehensive income related to these cash flow hedges will be recognized in earnings as the related contracts are settled, if the hedge becomes ineffective, or if it is probable that the hedged transaction will not occur. During the nine months ended September 30, 2005, and September 30, 2004, we reclassified a $3.1 million and a $2.8 million net-of-tax gain, respectively, from other comprehensive income into earnings as a result of the discontinuance of cash flow hedge accounting for certain hedge transactions. In the next 12 months, subject to changes in market prices of natural gas and electricity, we expect that a net-of-tax loss of $27.4 million will be recognized in earnings as contracts are settled. We expect this amount to be substantially offset by settlement of the related nonderivative contracts.

In the second quarter of 2005, a variable rate non-recourse debt instrument used to finance the purchase of Sunbury was restructured to a WPS Resources obligation. An interest rate swap used to fix the interest rate on the Sunbury non-recourse debt had been previously designated as a cash flow hedge. As a result of the debt restructuring, the hedged transaction will no longer occur. This resulted in the recognition of a $9.1 million pre-tax loss (equivalent to the mark-to-market value of the swap at the date of restructuring), which was recorded as a component of interest expense in the second quarter of 2005. This loss was previously deferred as a component of other comprehensive income pursuant to hedge accounting rules. Subsequent to the restructuring, the interest rate swap was re-designated as a cash flow hedge, along with an additional interest rate swap, to fix the interest rate on the WPS Resources obligation. The changes in the fair value of the effective portion of these swaps are included in other comprehensive income, net of deferred taxes, while the changes related to the ineffective portion are recorded in earnings. During the nine months ended September 30, 2005, cash flow hedge ineffectiveness recorded in earnings related to these swaps was not significant. Amounts recorded in other comprehensive income related to these swaps will be recognized as a component of interest expense as the interest becomes due. In the next 12 months, we expect to recognize $0.1 million in interest expense related to these swaps, assuming interest rates comparable to those at September 30, 2005. We did not exclude any components of the derivative instruments' change in fair value from the assessment of hedge effectiveness.

NOTE 4--ASSETS HELD FOR SALE

In the second quarter of 2005, PDI sold all of Sunbury's allocated emission allowances. Prior to this decision, PDI had marketed for sale the Sunbury plant and certain other related assets (primarily inventory and unallocated emission allowances) in combination with the allocated emission allowances. The Sunbury facility sells power on a wholesale basis and previously provided energy for a 200-megawatt around-the-clock outtake contract that expired on December 31, 2004. Following Duquesne Power, L.P.'s termination of the previously announced agreement to sell Sunbury to Duquesne for approximately $120 million, PDI continued to pursue the sale of Sunbury with the assistance of an investment banking firm, but a suitable buyer was not found.

Total sales proceeds from the sale of Sunbury's emission allowances were $109.9 million, resulting in a pre-tax gain of $85.9 million. The sale of the emission allowances provides PDI with more time to consider various alternatives for the Sunbury plant. All available solid fuel units at the Sunbury plant were operated through September 30, 2005 due to favorable market conditions. Should market conditions decline, PDI will consider placing the plant in a stand-by mode of operation, which serves to minimize

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future operating expenses while maintaining several options (including closing the plant, retaining the plant and operating it during favorable economic periods, or a potential future sale of the plant).

Prior to the decision to sell the allocated emission allowances separately, the Sunbury plant, allocated emission allowances, and other related assets had been classified as held for sale as a combined asset disposal group, and Sunbury's results of operations and related cash flows had been reported as discontinued operations. However, because PDI is no longer committed to the sale of Sunbury as its only option, generally accepted accounting principles require those assets and liabilities previously classified as held for sale that no longer meet the held for sale criteria outlined in SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," to be reclassified to the appropriate held and used categories for all periods presented. As a result, the allocated emission allowances that were sold in May 2005 remain classified as held for sale for all applicable periods presented, but the Sunbury plant, unallocated emission allowances, and other related assets and liabilities were reclassified as held and used. Furthermore, Sunbury's results of operations were reclassified as components of continuing operations for all periods presented.

All long-lived assets reclassified as held and used are required to be recorded individually at the lower of their carrying value before they were classified as assets held for sale (adjusted for any depreciation expense that would have been recognized had they been continuously classified as held and used) or fair value at the date the held for sale criteria was no longer met. Upon reclassification of the Sunbury plant and related assets as held and used in the second quarter of 2005, PDI recorded a non-cash, pre-tax impairment charge of $80.6 million. The impairment charge substantially offset the gain on the sale of the emission allowances.

The major classes of assets held for sale are as follows:


	September 30,		December 31,
(Millions)	2005		2004
Property, plant, and equipment, net	$	0.8	$	0.8
Other assets:
Emission allowances		-		23.3
Assets held for sale	$	0.8	$	24.1

PDI financed Sunbury with equity from WPS Resources and debt financing, including non-recourse debt and a related interest rate swap. The interest rate swap was designated as a cash flow hedge. WPS Resources is required to recognize the amount accumulated within other comprehensive income currently in earnings if management determines that the hedged transactions (i.e., future interest payments on the debt) will not continue. Sunbury's non-recourse debt was restructured to a WPS Resources obligation in the second quarter of 2005 in conjunction with the sale of Sunbury's allocated emission allowances. The restructuring of the Sunbury non-recourse debt to a WPS Resources obligation triggered a $9.1 million pre-tax loss (the mark-to-market value of the swap at the date of the restructuring), which was recorded as a component of interest expense in the second quarter of 2005. This loss was previously deferred as a component of other comprehensive income pursuant to hedge accounting rules.

NOTE 5--ACQUISITIONS AND SALES OF ASSETS

Agreement to Purchase Aquila's Michigan and Minnesota Natural Gas Distribution Operations

On September 21, 2005, WPS Resources, through wholly owned subsidiaries, entered into two definitive agreements with Aquila, Inc. to acquire Aquila's natural gas distribution operations in Michigan and Minnesota for approximately $558 million, exclusive of direct costs of the acquisition. The purchase price also excludes certain adjustments related to working capital, including accounts receivable, unbilled revenue, inventory, and certain other current assets. The purchase price is also subject to certain other closing and post-closing adjustments, primarily net plant adjustments.

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The Minnesota natural gas assets provide natural gas distribution service to about 200,000 customers throughout the state in 165 cities and communities including Grand Rapids, Pine City, Rochester, and Dakota County with 226 employees. Annual natural gas throughput is approximately 761 million therms per year, which is almost as large as WPS Resources' existing regulated natural gas operations. The assets operate under a cost-of-service environment and are currently allowed an 11.71% return on equity on a 50% equity component of the regulatory capital structure.

The Michigan natural gas assets provide natural gas distribution service to about 161,000 customers, mainly in southern Michigan in 147 cities and communities including Otsego, Grand Haven, and Monroe with 182 employees. Annual natural gas throughput is approximately 360 million therms per year. Like Minnesota, the assets also operate under a cost-of-service environment and are currently allowed an 11.4% return on equity on a 45% equity component of the regulatory capital structure.

WPS Resources plans that permanent financing for the acquisition will be raised through the issuance of a combination of equity and long-term debt.

The transaction is subject to various state and other regulatory approvals, including approval from the Michigan Public Service Commission and the Minnesota Public Utilities Commission, and is subject to compliance with the Hart-Scott-Rodino Act. Assuming all approvals are obtained in a timely manner, WPS Resources anticipates closing both transactions in the first half of 2006.

Kewaunee Nuclear Power Plant

In early July 2005, Kewaunee returned to service following an unplanned outage that began in February 2005. On July 5, 2005, WPSC completed the sale of its 59% ownership interest in Kewaunee to Dominion Energy Kewaunee, LLC, a subsidiary of Dominion Resources, Inc. At the same time, Wisconsin Power and Light Company sold its 41% ownership interest to Dominion. The major benefits of the sale for WPSC included shifting financial risk from utility customers and shareholders to Dominion, greater certainty of future costs, and the return of the nonqualified decommissioning funds to customers.

WPSC's share of the cash proceeds from the sale was $112.5 million. Dominion received the assets in WPSC's qualified decommissioning trust and assumed responsibility for the eventual decommissioning of Kewaunee. These trust assets had a pre-tax fair value of $243.6 million at closing. WPSC retained ownership of the assets contained in its nonqualified decommissioning trust. The sale of Kewaunee resulted in a loss of $12.1 million, which includes the proceeds from the sale less the net assets sold, adjusted by several additional items. The most significant of these adjustments is the fair value of an indemnity issued to cover certain costs Dominion may incur related to the recent unplanned outage. In addition, the adjustments include certain costs related to the termination of the plant operating agreement and withdrawal from WPS Resources' investment in the Nuclear Management Company ("NMC"), which served as the licensed operator of Kewaunee. WPSC has received approval from the PSCW for deferral of the loss resulting from this transaction and related costs. WPSC has proposed that proceeds of $127.1 million received from the liquidation of the nonqualified decommissioning trust assets be refunded to customers, net of the loss on the sale of the plant assets and costs related to the 2004 and 2005 Kewaunee outages. See Note 16, Regulatory Environment, for more information.

At the closing date, WPSC's share of the carrying value of the assets and liabilities that were included within the sale agreement, or that were otherwise eliminated pursuant to the sale, were as follows:

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(Millions)	July 5, 2005

Qualified decommissioning trust fund	$	243.6
Other utility plant, net		165.4
Other current assets		5.5
Total assets	$	414.5

Regulatory liabilities	$	(72.1	)
Accounts payable		2.5
Asset retirement obligations		376.4
Total liabilities	$	306.8

Upon the closing of the sale, WPSC entered into a long-term power purchase agreement with Dominion to purchase energy and capacity consistent with volumes available when WPSC owned Kewaunee. The power purchase agreement extends through 2013 when the plant's current operating license will expire. Fixed monthly payments under the power purchase agreement will approximate the expected costs of production had WPSC continued to own the plant. Therefore, management believes that the sale of Kewaunee and the related power purchase agreement provides more price certainty for WPSC's customers and reduces WPSC's risk profile. In April 2004, WPSC entered into an exclusivity agreement with Dominion. Under this agreement, if Dominion decides to extend the operating license of Kewaunee, Dominion can negotiate only with WPSC during the exclusivity period for 59% of the plant output under a new power purchase agreement that would extend beyond Kewaunee's current operating license termination date. The exclusivity period started on the closing date of the sale, July 5, 2005, and extends through December 21, 2011, after which Dominion can negotiate with other parties.

NOTE 6--GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill recorded by WPS Resources was $36.8 million at September 30, 2005, and December 31, 2004. Of this amount, $36.4 million is recorded in WPSC's natural gas segment relating to its merger with Wisconsin Fuel and Light. The remaining $0.4 million of goodwill relates to PDI.

Goodwill and purchased intangible assets are included in other assets on the Condensed Consolidated Balance Sheets. Emission allowances are recorded at the lower of cost or market. Information in the tables below relates to total purchased identifiable intangible assets for the periods indicated.


*(Millions)*	September 30, 2005
Asset Class	Average Life (Years)		Gross Carrying Amount		Accumulated Amortization			Net
Emission allowances		1 to 30	$	16.7	$	(13.0	)	$	3.7
Customer related		1 to 8		10.5		(5.2	)		5.3
Other		1 to 30		4.2		(1.6	)		2.6
Total			$	31.4	$	(19.8	)	$	11.6


(Millions)	December 31, 2004
Asset Class		Average Life (Years)		Gross Carrying Amount		Accumulated Amortization			Net
Emission allowances		1 to 30	$	15.8	$	(0.9	)	$	14.9
Customer related		1 to 8		11.2		(4.6	)		6.6
Other		1 to 30		4.2		(1.6	)		2.6
Total			$	31.2	$	(7.1	)	$	24.1

An impairment charge related to Sunbury, which was recorded in the second quarter of 2005, included the write-down of $6.6 million of unallocated emission allowances. These emission allowances were reflected in the above table at December 31, 2004 (see Note 4, Assets Held for Sale, for more

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information). Because PDI sold all of Sunbury's allocated emission allowances in the first half of 2005, emission allowances are currently purchased in the market as needed for the operation of this plant.

Intangible asset amortization expense, in the aggregate, for the nine months ended September 30, 2005, and September 30, 2004, was $13.1 million and $1.7 million, respectively. Intangible asset amortization expense, in the aggregate, for the three months ended September 30, 2005, and September 30, 2004, was $10.1 million and $1.0 million, respectively. Amortization expense for the next five fiscal years is estimated as follows:

Estimated Future Amortization Expense:
For three months ending December 31, 2005	$1.9 million
For year ending December 31, 2006	1.6 million
For year ending December 31, 2007	1.3 million
For year ending December 31, 2008	1.5 million
For year ending December 31, 2009	1.2 million

NOTE 7--SHORT-TERM DEBT AND LINES OF CREDIT

WPS Resources has a syndicated $500 million five-year revolving credit facility which expires in June 2010. WPSC has a syndicated $115 million five-year revolving credit facility containing annual trigger date provisions to provide short-term borrowing flexibility and security for commercial paper outstanding.

The information in the table below relates to WPS Resources' short-term debt and lines of credit as of the time periods indicated.


(Millions)	September 30, 2005			December 31, 2004
Commercial paper outstanding	$	138.0		$	279.7
Average discount rate on outstanding commercial paper		3.95	%		2.46	%
Short-term notes payable outstanding	$	10.0		$	12.7
Average interest rate on short-term notes payable		3.67	%		2.52	%
Available under lines of credit	$	404.5		$	161.9

The commercial paper at September 30 had varying maturity dates ranging from October 3 through October 17, 2005.

The information in the table below relates to WPSC's short-term debt and lines of credit as of the time periods indicated.


(Millions)	September 30, 2005			December 31, 2004
Commercial paper outstanding	$	32.0		$	91.0
Average discount rate on outstanding commercial paper		3.94	%		2.44	%
Short-term notes payable outstanding	$	10.0		$	10.0
Average interest rate on short-term notes payable		3.67	%		2.26	%
Available under lines of credit	$	79.2		$	20.2

The commercial paper had varying maturity dates ranging from October 7 through October 17, 2005.

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NOTE 8--LONG-TERM DEBT

(Millions)			September 30, 2005	December 31, 2004

First mortgage bonds – WPSC
	Series	Year Due
	6.90%	2013	$ 22.0	$ 22.0
	7.125%	2023	0.1	0.1

Senior notes – WPSC
	Series	Year Due
	6.125%	2011	150.0	150.0
	4.875%	2012	150.0	150.0
	4.80%	2013	125.0	125.0
	6.08%	2028	50.0	50.0

First mortgage bonds – UPPCO
	Series	Year Due
	9.32%	2021	15.3	15.3

Unsecured senior notes – WPS Resources
	Series	Year Due
	7.00%	2009	150.0	150.0
	5.375%	2012	100.0	100.0

Unsecured term loan due 2010 – WPS Resources			65.6	-
Term loans – non-recourse, collateralized by nonregulated assets			17.7	82.3
Tax exempt bonds			27.0	27.0
Senior secured note			2.5	2.7
Total			875.2	874.4
Unamortized discount and premium on bonds and debt			(1.9)	(2.0)
Total long-term debt			873.3	872.4
Less current portion			(3.7)	(6.7)
Total long-term debt			$869.6	$865.7

On June 17, 2005, $62.9 million of non-recourse debt at PDI collateralized by nonregulated assets was converted to a five-year WPS Resources obligation as a result of the sale of Sunbury's allocated emission allowances. In addition, $2.7 million drawn on a line of credit at PDI was rolled into the five-year WPS Resources obligation. The floating interest rate on the total five-year WPS Resources’ obligation of $65.6 million has been fixed at 4.595% through two interest rate swaps.

NOTE 9--ASSET RETIREMENT OBLIGATIONS

Legal retirement obligations, as defined by the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations," previously identified at WPSC related primarily to the final decommissioning of Kewaunee. As discussed in Note 5, Acquisitions and Sales of Assets, the sale of Kewaunee to Dominion was completed on July 5, 2005. As a result of the sale, Dominion assumed the asset retirement obligation related to Kewaunee.

PDI identified a legal retirement obligation related to the closure of an ash basin located at Sunbury. The asset retirement obligation associated with Sunbury is recorded as a liability on the Condensed Consolidated Balance Sheets.

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The following table describes all changes to the asset retirement obligation liabilities of WPS Resources.


(Millions)	WPSC			PDI		Total
Asset retirement obligation at December 31, 2004	$	364.4		$	2.2	$	366.6
Accretion expense		12.4			0.2		12.6
Asset retirement obligation transferred to Dominion		(376.4	)		-		(376.4	)
Asset retirement obligation at September 30, 2005	$	0.4		$	2.4	$	2.8

NOTE 10--INCOME TAXES

For the three and nine months ended September 30, 2005, and 2004, WPS Resources' and WPSC's provision for income taxes was calculated in accordance with APB Opinion No. 28, "Interim Financial Reporting." Accordingly, our interim effective tax rate reflects our projected annual effective tax rate. The effective tax rate differs from the federal tax rate of 35%, primarily due to the effects of tax credits and state income taxes.

NOTE 11--COMMITMENTS AND CONTINGENCIES

Commodity and Purchase Order Commitments

WPS Resources routinely enters into long-term purchase and sale commitments that have various quantity requirements and durations. The commitments described below are as of September 30, 2005.

ESI has unconditional purchase obligations related to energy supply contracts that total $4.2 billion. Substantially all of these obligations end by 2009, with obligations totaling $16.5 million extending from 2010 through 2015. The majority of the energy supply contracts are to meet ESI's obligations to deliver energy to its customers.

WPSC has obligations related to coal, purchased power, and natural gas. All pertinent nuclear fuel contracts were assigned to Dominion with the July 5, 2005, sale of Kewaunee to Dominion. Obligations related to coal supply and transportation extend through 2016 and total $346.5 million. Through 2016, WPSC has obligations totaling $1.5 billion for either capacity or energy related to purchased power, including the obligation under the power purchase agreement with Dominion Kewaunee, LLC. Also, there are natural gas supply and transportation contracts with total estimated demand payments of $126.6 million through 2017. WPSC expects to recover these costs in future customer rates. Additionally, WPSC has contracts to sell electricity and natural gas to customers.

PDI has entered into purchase contracts totaling $6.8 million. The majority of these contracts relate to coal purchases for the PDI coal plants.

UPPCO has made commitments for the purchase of commodities, mainly capacity or energy related to purchased power, which total $26.4 million and extend through 2010.

WPS Resources also has commitments in the form of purchase orders issued to various vendors. At September 30, 2005, these purchase orders totaled $485.7 million and $471.6 million for WPS Resources and WPSC, respectively. The majority of these commitments relate to large construction projects, including construction of the 500-megawatt Weston 4 coal-fired generation facility near Wausau, Wisconsin.

EPA Section 114 Request

In November 1999, the EPA announced the commencement of a Clean Air Act enforcement initiative targeting the utility industry. This initiative resulted in the issuance of several notices of violation/findings of violation and the filing of lawsuits against utilities. In these enforcement proceedings, the EPA claims that the utilities made modifications to the coal-fired boilers and related equipment at the utilities' electric generation stations without first obtaining appropriate permits under the EPA's pre-construction permit program and without installing appropriate air pollution control equipment. In addition, the EPA is

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claiming, in certain situations, that there were violations of the Clean Air Act's "new source performance standards." In the matters where actions have been commenced, the federal government is seeking penalties and the installation of pollution control equipment.

In December 2000, WPSC received from the EPA a request for information under Section 114 of the Clean Air Act. The EPA sought information and documents relating to work performed on the coal-fired boilers located at WPSC's Pulliam and Weston electric generation stations. WPSC filed a response with the EPA in early 2001.

On May 22, 2002, WPSC received a follow-up request from the EPA seeking additional information regarding specific boiler-related work performed on Pulliam Units 3, 5, and 7, as well as information on WPSC's life extension program for Pulliam Units 3-8 and Weston Units 1 and 2. WPSC made an initial response to the EPA's follow-up information request on June 12, 2002, and filed a final response on June 27, 2002.

In 2000 and 2002, Wisconsin Power and Light Company received a similar series of EPA information requests relating to work performed on certain coal-fired boilers and related equipment at the Columbia generation station (a facility located in Portage, Wisconsin, jointly owned by Wisconsin Power and Light Company, Madison Gas and Electric Company, and WPSC). Wisconsin Power and Light Company is the operator of the plant and is responsible for responding to governmental inquiries relating to the operation of the facility. Wisconsin Power and Light Company filed its most recent response for the Columbia facility on July 12, 2002.

Depending upon the results of the EPA's review of the information, the EPA may issue "notices of violation" or "findings of violation" asserting that a violation of the Clean Air Act occurred and/or seek additional information from WPSC and/or third parties who have information relating to the boilers or close out the investigation. To date, the EPA has not responded to the filings made by WPSC and Wisconsin Power and Light. In addition, under the federal Clean Air Act, citizen groups may pursue a claim.

In response to the EPA Clean Air Act enforcement initiative, several utilities have elected to settle with the EPA, while others are in litigation. In general, those utilities that have settled have entered into consent decrees which require the companies to pay fines and penalties, undertake supplemental environmental projects, and either upgrade or replace pollution controls at existing generating units or shut down existing units and replace these units with new electric generating facilities. Several of the settlements involve multiple facilities. The fines and penalties (including the capital costs of supplemental environmental projects) associated with these settlements range between $7 million and $44 million. Factors typically considered in settlements include, but are not necessarily limited to, the size and number of facilities as well as the duration of alleged violations and the presence or absence of aggravating circumstances. The regulatory interpretations upon which the lawsuits or settlements are based may change based on future court decisions that may be rendered in pending litigations.

If the federal government decided to bring a claim against WPSC and if it were determined by a court that historic projects at WPSC's Pulliam and Weston plants required either a state or federal Clean Air Act permit, WPSC may, under the applicable statutes, be required to:

·	shut down any unit found to be operating in non-compliance,

·	install additional pollution control equipment,

·	pay a fine, and/or

·	pay a fine and conduct a supplemental environmental project in order to resolve any such claim.

At the end of December 2002 and October 2003, the EPA issued new rules governing the federal new source review program. These rules were subsequently challenged in the District of Columbia Circuit Court of Appeals. On June 24, 2005, the District of Columbia Circuit Court of Appeals issued its opinion on the EPA's 2002 new source review reform rule. The ruling upheld most of the 2002 rule, but did strike down some provisions. The rules are not yet effective in Wisconsin. They are also not retroactive.

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Wisconsin has proposed amending its new source review program to substantially conform to the federal regulations. The Wisconsin rules are not anticipated to be finalized before 2006.

Pulliam Air Permit Violation Lawsuit

On July 12, 2005, the Sierra Club and Clean Wisconsin notified WPS Resources of their intent to file a citizen enforcement action with the United States District Court, Eastern District of Wisconsin, pursuant to the citizen suit provisions of the Clean Air Act. The Sierra Club and Clean Wisconsin indicated that the lawsuit will seek penalties, injunctive relief, and costs of litigation. The notice referenced opacity exceedances reported by the Pulliam facility located in Green Bay, Wisconsin, from 1999 through the first quarter of 2005, and monitoring violations from 1999 through 2004. The notice also alleged exceedances of the Clean Air Act operating permit in 2002, exceedances of the permit issued for eight diesel generators in 2001, and exceedances of the permit for the combustine turbine.

On October 20, 2005, the Sierra Club and Clean Wisconsin filed a civil lawsuit claiming that WPSC's Pulliam facility located in Green Bay, Wisconsin violated provisions of its air permit with respect to particulates, nitrogen oxide, and visible emissions; however, WPSC has not been served to date. Sierra Club and Clean Wisconsin have stated a willingness to discuss the alleged violations. WPSC is investigating the claims.

Weston 4 Air Permit

On November 15, 2004, the Sierra Club filed a petition with the WDNR under Section 285.61, Wis. Stats., seeking a contested case hearing on the air permit issued for the Weston 4 generation station. On December 2, 2004, WDNR granted the petition and forwarded the matter to the Division of Hearings and Appeals. In its petition, Sierra Club raised legal and factual issues with the permit and with the process used by WDNR to develop the air emission limits and conditions. In addition, both WPSC and the Sierra Club filed motions for summary judgment on certain of the issues. A decision regarding summary judgment was issued. In the ruling, the Administrative Law Judge denied the motion of Sierra Club and granted summary judgment to WPSC with respect to certain claims of Sierra Club consistent with the rulings rendered in Wisconsin Energy's Elm Road proceeding. The contested case hearing in the matter was held during the last week of September 2005. The hearing addressed the remaining issues, which are generally related to the emission limits specified in the permit and the pollution controls to be used to achieve these limits. The Administrative Law Judge set a briefing schedule and indicated that a decision would be issued in January 2006. If the Administrative Law Judge's decision requires modifications to the air permit, construction delays and/or increased construction costs could result.

Weston Site Operation Permit

On April 18 and April 26, 2005, WPS Resources notified the WDNR that the existing Weston facility was not in compliance with certain provisions of the "Title V" air operating permit that was issued to the facility in October 2004. These provisions include: (1) the particulate emission limits applicable to the coal handling equipment; (2) the carbon monoxide limit for Weston combustion turbines; and (3) the limitation on the sulfur content of the fuel oil stored at the Weston facility. On July 27, 2005, WPSC received a notice of violation (NOV) from the WDNR asserting that the existing Weston facility is not in compliance with certain provisions of the permit. The alleged noncompliance is based on information previously provided by WPSC to the WDNR in April 2005. The NOV classifies certain alleged violations as "high priority" under the EPA's high priority violation policy. Under the WDNR’s stepped enforcement process, an NOV is the first step in the WDNR’s enforcement procedure. If the WDNR decides to continue the enforcement process, the next step is a “referral” of the matter to the Wisconsin Attorney General’s Office. WPS Resources is seeking to amend the applicable permit limits and is taking corrective action. At this time, we believe that our exposure to fines or penalties related to this noncompliance would not have a material impact on our financial results.

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Mercury and Interstate Air Quality Rules

On October 1, 2004, the mercury emission control rule became effective in Wisconsin. The rule requires WPSC to control annual system mercury emissions in phases. The first phase will occur in 2008 and 2009. In this phase, the annual mercury emissions are capped at the average annual system mercury emissions for the period 2002 through 2004. The next phase will run from 2010 through 2014 and requires a 40% reduction from average annual 2002 through 2004 mercury input amounts. After 2015, a 75% reduction is required with a goal of an 80% reduction by 2018. Because federal regulations were promulgated in March 2005, we believe the state of Wisconsin will revise the Wisconsin rule to be consistent with the federal rule. However, the state of Wisconsin has filed suit against the federal government along with other states in opposition to the rule. WPSC estimates capital costs of approximately $14 million to achieve the proposed 75% reductions. The capital costs are expected to be recovered in a future rate case.

In December 2003, the EPA proposed mercury "maximum achievable control technology" standards and an alternative mercury "cap and trade" program substantially modeled on the Clear Skies legislation initiative. The EPA also proposed the Clean Air Interstate Rule (formerly known as the Interstate Air Quality Rule), which would reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin, Michigan, Pennsylvania, and New York. In March 2005, the EPA finalized both the mercury rule and the Clean Air Interstate Rule.

The final mercury rule establishes New Source Performance Standards for new units based upon the type of coal burned. Weston 4 will install and operate mercury control technology with the aim of achieving a mercury emission rate less than that in the final EPA mercury rule.

The final mercury rule also establishes a mercury cap and trade program, which requires a 21% reduction in national mercury emissions in 2010 and a 70% reduction in national mercury emissions beginning in 2018. Based on the final rule and current projections, WPSC anticipates meeting the mercury rule cap and trade requirements at a cost similar to the cost to comply with the Wisconsin rule.

PDI's current analysis indicates that additional emission control equipment on its existing units may be required. Excluding Sunbury, PDI estimates the capital cost for the remaining units to be approximately $1 million to achieve a 70% reduction. Including Sunbury, the total PDI mercury control costs could approximate $33 million, depending upon how this facility is operated.

The final Clean Air Interstate Rule requires reduction of sulfur dioxide and nitrogen oxide emissions in two phases. The first phase requires about a 50% reduction beginning in 2009 for nitrogen oxide and beginning in 2010 for sulfur dioxide. The second phase begins in 2015 for both pollutants and requires about a 65% reduction in emissions. The rule allows the affected states (including Wisconsin, Michigan, Pennsylvania, and New York) to either require utilities located in the state to participate in the EPA's interstate cap and trade program or meet the state's emission budget for sulfur dioxide and nitrogen oxide through measures to be determined by the state. The states have not adopted a preference as to which option they would select, but the states are investigating the cap and trade program, as well as alternatives or additional requirements. Consequently, the effect of the rule on WPSC's and PDI's facilities is uncertain, since it depends upon how the states choose to implement the final Clean Air Interstate Rule.

Currently, WPSC is evaluating a number of options that include using the cap and trade program and/or installing controls. For planning purposes, it is assumed that additional sulfur dioxide and nitrogen oxide controls will be needed on existing units or the existing units will need to be converted to natural gas by 2015. The installation of any controls and/or any conversion to natural gas will need to be scheduled as part of WPSC's long-term maintenance plan for its existing units. As such, controls or conversions may need to take place before 2015. On a preliminary basis and assuming controls or conversion are required, WPSC estimates capital costs of $257 million in order to meet an assumed 2015 compliance date. This estimate is based on costs of current control technology and current information regarding the final EPA rule. The costs may change based on the requirements of the final state rules.

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PDI is evaluating the compliance options for the Clean Air Interstate Rule. Additional nitrogen oxide controls on some of PDI's facilities may be necessary, and would cost approximately $41 million. The cost estimate is largely dependent upon how Sunbury will be operated going forward. See Note 4, Assets Held for Sale, for additional information on Sunbury. Additional sulfur dioxide reductions are unlikely. Also, PDI will evaluate a number of options including using the cap and trade program, fuel switching, and/or installing controls.

Clean Air Regulations

Most of the generation facilities owned by PDI are located in an ozone transport region. As a result, these generation facilities are subject to additional restrictions on emissions of nitrogen oxide. Throughout 2005 and in future years, PDI estimates purchasing nitrogen oxide emission allowances at market rates, as needed, to meet its requirements for the Sunbury generation facility.

PDI began 2005 with 17,000 sulfur dioxide emission allowances for its generation facilities that are required to participate in the sulfur dioxide emission program. However, a majority of these allowances were sold in the second quarter of 2005, requiring a higher level of purchases for the remainder of the year. During the remainder of 2005 and in future years, PDI estimates purchasing sulfur dioxide allowances at market rates, as needed, to meet its requirements for the Sunbury generation facility.

Other Environmental Issues

Groundwater testing at a former ash disposal site of UPPCO indicated elevated levels of boron and lithium. Supplemental remedial investigations were performed, and a revised remedial action plan was developed. The Michigan Department of Environmental Quality approved the plan in January 2003. UPPCO received an order from the MPSC permitting deferral and future recovery of these costs. A liability of $1.4 million and an associated regulatory asset of $1.4 million were recorded for estimated future expenditures associated with remediation of the site. UPPCO has an informal agreement, with the owner of another landfill, under which UPPCO has agreed to pay 17% of the investigation and remedial costs. It is estimated that the cost of addressing the site over the next 3 years will be $1.6 million. UPPCO has recorded $0.3 million of this amount as its share of the liability as of September 30, 2005.

Manufactured Gas Plant Remediation

WPSC continues to investigate the environmental cleanup of ten manufactured gas plant sites. Cleanup of the land portion of the Oshkosh, Stevens Point, Green Bay, Manitowoc, and two Sheboygan sites is completed. Groundwater treatment and monitoring at these sites will continue into the future. Cleanup of the land portion of four sites will be addressed in the future. River sediment remains to be addressed at sites with sediment contamination, and priorities will be determined in consultation with the EPA. In late 2004, WPSC purchased the Menominee site property. Clean up of this site is expected to begin in the near future. Work at the other sites remains to be scheduled.

WPSC is currently in the process of transferring sites with sediment contamination formally under WDNR jurisdiction to the EPA Superfund Alternatives Program. Under the EPA's program, the remedy decision will be based on risk-based criteria typically used at Superfund sites. WPSC estimated the future undiscounted investigation and cleanup costs as of September 30, 2005, to be $65.3 million. WPSC may adjust these estimates in the future contingent upon remedial technology, regulatory requirements, remedy determinations, and the assessment of natural resource damages. WPSC has received $12.7 million to date in insurance recoveries. WPSC expects to recover actual cleanup costs, net of insurance recoveries, in future customer rates. Under current PSCW policies, WPSC will not recover carrying costs associated with the cleanup expenditures.

Stray Voltage Claims

From time to time, WPSC has been sued by dairy farmers who allege that they have suffered loss of milk production and other damages supposedly due to "stray voltage" from the operation of WPSC's electrical system. Past cases have been resolved without any material adverse effect on the financial statements

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of WPSC. One case, Allen v. WPSC, has been remanded from the court of appeals to the trial court for a determination of whether a post-verdict injunction is warranted. A second case, Pollack v. WPSC, was tried and ended in a defense verdict on May 5, 2005, and that case is concluded. A third case, Seidl v. WPSC, was tried to a jury in October 2004, but ended in a mistrial. On June 21, 2005, the trial judge granted WPSC's motion for a directed verdict. The Seidl plaintiffs have filed a notice of appeal of that dismissal.

The PSCW has established certain requirements regarding stray voltage for all utilities subject to its jurisdiction. The PSCW has defined what constitutes "stray voltage," established a level of concern at which some utility corrective action is required, and set forth test protocols to be employed in evaluating whether a stray voltage problem exists. Based upon the information available to it to date, WPSC believes that it was in compliance with the PSCW's orders, and the plaintiffs did not have a stray voltage problem as defined by the PSCW for which WPSC is responsible. Nonetheless, in 2003, the Supreme Court of Wisconsin ruled in the case Hoffmann v. WEPCO that a utility could be liable in tort to a farmer for damage from stray voltage even though the utility had complied with the PSCW's established level of concern.

On February 15, 2005, the Court of Appeals affirmed the jury verdict in Allen v. WPSC, which awarded the plaintiff approximately $0.8 million for economic damages and $1 million for nuisance. The Court of Appeals also remanded to the trial court the issue of whether an injunction should be issued for additional proceedings. The Supreme Court of Wisconsin denied WPSC's petition to review the Court of Appeals decision. The judgment has been paid to the plaintiff. The trial judge must now decide whether an injunction should be issued. The expert witnesses retained by WPSC do not believe that there is any scientific basis for concluding that electricity from the utility system is currently creating any problem on the plaintiff's land. Accordingly, WPSC does not believe there is any basis for issuing an injunction, and intends to vigorously contest the portion of the case that will be remanded for further proceedings.

On August 2, 2005, a judgment was entered dismissing the Seidls’ stray voltage case and awarding WPSC its costs, which were approximately $63,000. On September 14, 2005, the Seidls filed a notice of appeal from that judgment. The appeal asserts that the trial court did not have jurisdiction to grant the motion to dismiss because of the passage of time, and that there was sufficient evidence in the record that WPSC was negligent in distributing electricity to the Seidls to require a jury to resolve that issue. It typically takes about a year to resolve appeals. WPSC believes it has meritorious arguments which support the judgment and plans to vigorously contest the appeal.

WPSC has insurance coverage for the pending claims, but the policies have customary self-insured retentions per occurrence. Based upon the information known at this time and the availability of insurance, WPSC believes that the total cost to it of resolving the two remaining actions will not be material.

Flood Damage

On May 14, 2003, a fuse plug at the Silver Lake reservoir owned by UPPCO was breached. This breach resulted in subsequent flooding downstream on the Dead River, which is located in Michigan's Upper Peninsula near Marquette, Michigan.

A dam owned by Marquette Board of Light and Power, which is located downstream from the Silver Lake reservoir near the mouth of the Dead River, also failed during this event. In addition, high water conditions and siltation resulted in damage at the Presque Isle Power Plant owned by Wisconsin Electric Power Company. Presque Isle, which is located downstream from the Marquette Board of Light and Power dam, was ultimately forced into a temporary shutdown.

The FERC's Independent Board of Review issued its report in December of 2003 and concluded that the root cause of the incident was the failure of the design of the fuse plug to take into account the highly erodible nature of the fuse plug's foundation materials and spillway channel, resulting in the complete loss of the fuse plug, foundation, and spillway channel, which caused the release of Silver Lake far beyond the

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intended design of the fuse plug. The fuse plug for the Silver Lake reservoir was designed by an outside engineering firm.

UPPCO has worked with federal and state agencies in their investigations. UPPCO is still in the process of investigating the incident. WPS Resources maintains a comprehensive insurance program that includes UPPCO and which provides both property insurance for its facilities and liability insurance for liability to third parties. WPS Resources is insured in amounts that it believes are sufficient to cover its responsibilities in connection with this event. Deductibles and self-insured retentions on these policies are not material to WPS Resources.

As of May 13, 2005, several lawsuits were filed by the claimants and putative defendants relating to this incident. The suits that have been filed against UPPCO, WPS Resources, and WPSC include the following claimants: WE Energies, Cleveland Cliffs, Inc., Board of Light and Power of the City of Marquette, the City of Marquette, the County of Marquette, Dead River Campers, Inc., Marquette County Road Commission, SBC, and various land and homeowners along the Silver Lake reservoir and Dead River system. WPS Resources is defending these lawsuits and is seeking resolution of all claims and litigation where possible. UPPCO filed a suit against the engineering company that designed the fuse plug (MWH Americas, Inc.) and the contractor who built it (Moyle Construction, Inc.).

In November 2003, UPPCO received approval from the MPSC and the FERC for deferral of costs that are not reimbursable through insurance or recoverable through the power supply cost recovery mechanism. Recovery of costs deferred will be addressed in future rate proceedings.

In January 2005, UPPCO announced its decision to restore Silver Lake as a reservoir for power generation, pending approval of a design by FERC. FERC has required that a board of consultants evaluate and oversee the new construction. The board of consultants is expected to review the design options in the fall of 2005, prior to construction, with construction expected to be completed in 2006.

Wausau, Wisconsin, to Duluth, Minnesota, Transmission Line

Construction of the 220-mile, 345-kilovolt Wausau, Wisconsin, to Duluth, Minnesota, transmission line began in the first quarter of 2004 with the Minnesota portion completed in early 2005. Construction in Wisconsin began on August 8, 2005.

ATC has assumed primary responsibility for the overall management of the project and will own and operate the completed line. WPSC received approval from the PSCW and the FERC to transfer ownership of the project to ATC. WPSC will continue to manage obtaining the private property rights, design, and construction of the Wisconsin portion of the project.

In December 2003, the PSCW issued an amended Certificate of Public Convenience and Necessity per ATC's request for relief. This decision was appealed to the Dane County Circuit Court by certain landowners. The court affirmed the PSCW's decision, and no appeal has been filed during the allowed time allotted for appeals. On July 25, 2005, the Administrative Law Judge issued the WDNR permit and water quality certification, subject to certain conditions. The conditions were acceptable to ATC and WPSC. Project opponents did not file an appeal of the Administrative Law Judge’s decision within the specified time, and it too is final. In addition, on August 5, 2005, the new law allowing condemnation of county land for transmission lines approved by the PSCW became effective. In light of this legislation, Douglas County negotiated an easement agreement with ATC that allows the project to be constructed across county land on the route originally selected by the PSCW. On September 15, 2005, the County Board approved that agreement. Accordingly, the lawsuit against Douglas County to force it to provide easements for the project is being dismissed as moot, and ATC has asked the PSCW to close the docket which was opened to examine alternative routes in Douglas County.

WPS Resources committed to fund 50% of total project costs incurred up to $198 million and will receive additional equity in the ATC in exchange for the project funding. Under its agreement to fund approximately half of the Wausau to Duluth transmission line, WPS Resources invested $35.4 million in the ATC for the nine months ended September 30, 2005, bringing WPS Resources’ investment in the

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ATC related to the project to $63.0 million since the inception of the project. WPS Resources may terminate funding if the project extends beyond January 1, 2010. On December 19, 2003, WPSC and ATC received approval from the PSCW to continue the project at a revised cost estimate of $420.3 million to reflect additional costs for the project resulting from time delays, added regulatory requirements, changes and additions to the project, and ATC overhead costs. WPS Resources has the right, but not the obligation, to provide additional funding in excess of $198 million for up to 50% of the revised cost estimate. The final portion of the line is expected to be placed in service in 2008. Allete, Inc. has an option to fund a portion of this commitment and intends to fund $60 million by the end of 2006. This would ultimately decrease the amount of additional equity WPS Resources has in the ATC. For the period October 2005 through November 2008, WPS Resources expects to fund up to approximately $141 million for its portion of the Wausau to Duluth transmission line assuming Allete, Inc. does not exercise its option, and approximately $81 million if Allete, Inc. does exercise this option.

Beaver Falls

PDI's Beaver Falls generation facility in New York has been out of service since late June 2005. An unplanned outage was caused by the failure of the first stage turbine blades. At this time, inclusive of estimated insurance recoveries, PDI estimates that it will cost between $3 million and $5 million to repair the turbine and replace the damaged blades. If the estimated repair costs are subsequently revised upward or if the repair costs are not fully recoverable through insurance, then a possibility exists that the repairs either will not be made or will cause the undiscounted cash flows related to future operations to be insufficient to recover the carrying value of the plant, resulting in an impairment. The carrying value of the Beaver Falls generation facility at September 30, 2005, is $18.6 million.

Synthetic Fuel Production Facility

We have significantly reduced our consolidated federal income tax liability for the past four years through tax credits available to us under Section 29 of the Internal Revenue Code for the production and sale of solid synthetic fuel from coal. These tax credits are scheduled to expire at the end of 2007 and are provided as an incentive for taxpayers to produce fuels from alternate sources and reduce domestic dependence on imported oil. This incentive is not deemed necessary if the price of oil increases sufficiently to provide a natural market for these fuels. Therefore, the tax credit in a given year is subject to phase out if the reference price of oil within that year exceeds a threshold price and is eliminated entirely if the reference price increases beyond a phase-out price. The reference price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. The threshold price at which the credit begins to phase out was set in 1980 and is adjusted annually for inflation. For 2004, the reference price was $36.75, the threshold price was $51.35, and the credits would have been eliminated had the reference price exceeded $64.47. For 2005, the estimated threshold price is $52.57, and the credits will be eliminated if the reference price exceeds $65.99.

Numerous events have recently increased domestic crude oil prices, including concerns about terrorism, storm-related supply disruptions, and worldwide demand. Although we do not expect the amount of our 2005 Section 29 tax credits to be adversely affected by oil prices given the current forward price curve for crude oil, we cannot predict with any certainty the future price of a barrel of oil. Therefore, in order to manage exposure to the risk of an increase in oil prices that could reduce the amount of 2005, 2006, and 2007 Section 29 tax credits that could be recognized, PDI entered into a series of derivative contracts covering a specified number of barrels of oil. These derivatives mitigate approximately 100%, 95%, and 40% of the Section 29 tax credit exposure in 2005, 2006, and 2007, respectively. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the average NYMEX trading price of oil in relation to the strike price of each option.

Our ability to fully utilize the Section 29 tax credits available to us in connection with our remaining interest in a synthetic fuel production facility will depend on whether the amount of our federal income tax liability is sufficient to permit the use of such credits. Other future tax legislation and Internal Revenue Service review may also affect the value of the tax credits and the value of our share of the facility. In 2005, we recognized $24.1 million in Section 29 tax credits. At September 30, 2005, we determined that it was not necessary to record a reserve against any portion of the deferred tax asset related to these

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credits. We have recorded the tax benefit of approximately $133.3 million of Section 29 tax credits as reductions to income tax expense from the project's inception in June 1998 through September 30, 2005. As a result of alternative minimum tax rules, approximately $71.6 million of this tax benefit has been carried forward as a deferred tax asset as of September 30, 2005. These alternative minimum tax credits can be carried forward indefinitely. The tax benefit recorded with respect to WPS Resources' share of tax credits from the facility is based on our expected consolidated tax liability for all open tax years including the current year, and all future years in which we expect to utilize deferred tax credits to offset our future tax liability. Reductions in our expected consolidated tax liability for any of these years could result in disallowance of previously recorded credits, and/or a change in the amount of the tax benefit deferred to future periods.

A portion of future payments under one of the agreements covering the sale of a portion of our interest in the facility is contingent on the facility's continued production of synthetic fuel. In the event of a

Section 29 tax credit phase-out in 2006 and 2007, a possibility exists that the level of synthetic fuel production at the facility would be reduced. If the facility reduces production, PDI may see an adjustment in the $7 million annual pre-tax gains expected to be realized through 2007 from the sell-down.

Dairyland Power Cooperative

Dairyland Power Cooperative has confirmed its intent to purchase a 30% interest in Weston 4 by signing a joint plant agreement in November 2004, subject to a number of conditions. The agreement with Dairyland Power Cooperative is part of our continuing plan to provide least-cost, reliable energy for the increasing electric demand of our customers. WPS Resources anticipates closing on the agreement with Dairyland Power Cooperative by the end of 2005, at which time Dairyland Power Cooperative will remit payment to WPSC in an amount equal to 30% of total costs already incurred by WPSC related to Weston 4 and thereafter will fund 30% of future costs.

NOTE 12--EMPLOYEE BENEFIT PLANS

The following table provides the components of net periodic benefit cost for WPS Resources' benefit plans for the three months ended September 30:


WPS Resources	Pension Benefits						Other Benefits
(Millions)	2005			2004			2005			2004
Net periodic benefit cost
Service cost	$	6.0		$	5.2		$	2.0		$	1.8
Interest cost		10.0			10.0			4.1			4.1
Expected return on plan assets		(10.9	)		(11.5	)		(3.1	)		(2.9	)
Amortization of transition obligation		-			-			0.1			0.1
Amortization of prior-service cost (credit)		1.3			1.4			(0.6	)		(0.5	)
Amortization of net loss		2.2			1.2			1.4			0.7
Net periodic benefit cost	$	8.6		$	6.3		$	3.9		$	3.3

WPSC's share of net periodic benefit cost for the three months ended September 30 is included in the table below:


WPSC	Pension Benefits						Other Benefits
(Millions)	2005			2004			2005			2004
Net periodic benefit cost
Service cost	$	4.8		$	4.2		$	1.9		$	1.6
Interest cost		8.4			8.3			3.7			3.7
Expected return on plan assets		(9.6	)		(10.2	)		(3.0	)		(2.8	)
Amortization of transition obligation		-			-			0.1			0.1
Amortization of prior-service cost (credit)		1.2			1.3			(0.5	)		(0.5	)
Amortization of net loss		1.5			0.5			1.2			0.6
Net periodic benefit cost	$	6.3		$	4.1		$	3.4		$	2.7

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The following table provides the components of net periodic benefit cost for WPS Resources' benefit plans for the nine months ended September 30:


WPS Resources	Pension Benefits						Other Benefits
(Millions)	2005			2004			2005			2004
Net periodic benefit cost
Service cost	$	17.9		$	15.4		$	6.0		$	5.7
Interest cost		30.2			29.9			12.4			12.8
Expected return on plan assets		(32.7	)		(34.4	)		(9.4	)		(8.7	)
Amortization of transition obligation		0.1			0.1			0.3			0.3
Amortization of prior-service cost (credit)		4.0			4.3			(1.6	)		(1.7	)
Amortization of net loss		6.5			3.3			4.1			3.4
Net periodic benefit cost	$	26.0		$	18.6		$	11.8		$	11.8

WPSC's share of net periodic benefit cost for the nine months ended September 30 is included in the table below:


WPSC	Pension Benefits						Other Benefits
(Millions)	2005			2004			2005			2004
Net periodic benefit cost
Service cost	$	14.5		$	12.5		$	5.6		$	5.2
Interest cost		25.1			24.9			11.3			11.5
Expected return on plan assets		(28.7	)		(30.6	)		(9.1	)		(8.5	)
Amortization of transition obligation		0.1			0.1			0.3			0.3
Amortization of prior-service cost (credit)		3.6			3.8			(1.4	)		(1.4	)
Amortization of net loss		4.3			1.6			3.5			2.6
Net periodic benefit cost	$	18.9		$	12.3		$	10.2		$	9.7

Contributions to the plans are made in accordance with legal and tax requirements and do not necessarily occur evenly throughout the year. For the nine months ended September 30, 2005, $8.2 million of contributions were made to the pension benefit plan, and no contributions were made to the other postretirement benefit plans. WPS Resources expects to contribute an additional $20.4 million to its other postretirement benefit plans in 2005.

NOTE 13--STOCK-BASED COMPENSATION

WPS Resources has four stock-based compensation plans: the 2005 Omnibus Incentive Compensation Plan ("2005 Omnibus Plan"), the 2001 Omnibus Incentive Compensation Plan ("2001 Omnibus Plan"), the 1999 Stock Option Plan ("Employee Plan"), and the 1999 Non-Employee Directors Stock Option Plan ("Director Plan"). No additional stock-based compensation will be issued under the 2001 Omnibus Plan or the Employee Plan, although the plans will continue to exist for purposes of the existing outstanding stock-based compensation.

WPS Resources accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Upon grant of stock options, no stock-based employee compensation cost is reflected in net income, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on income available for common shareholders and earnings per share if the company had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation:

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	Three Months Ended September 30,						Nine Months Ended September 30,
(Millions, except per share amounts)	2005			2004			2005			2004

Income available for common shareholders
As reported	$	48.2		$	34.8		$	138.0		$	82.0
Add: Stock-based compensation expense using the intrinsic value method - net of tax		0.3			0.2			1.6			0.7
Deduct: Stock-based compensation expense using the fair value method - net of tax		(0.4	)		(0.3	)		(1.1	)		(0.9	)
Pro forma	$	48.1		$	34.7		$	138.5		$	81.8

Basic earnings per common share
As reported	$	1.26		$	0.93		$	3.63		$	2.20
Pro forma		1.26			0.93			3.64			2.20

Diluted earnings per common share
As reported	$	1.25		$	0.93		$	3.60		$	2.19
Pro forma		1.25			0.92			3.62			2.18

NOTE 14--COMPREHENSIVE INCOME

SFAS No. 130, "Reporting Comprehensive Income," requires the reporting of other comprehensive income in addition to income available for common shareholders. Total comprehensive income includes all changes in equity during a period except those resulting from investments by shareholders and distributions to shareholders. WPS Resources' total comprehensive income is:


	Three Months Ended September 30,
(Millions)	2005			2004
Income available for common shareholders	$	48.2		$	34.8
Cash flow hedges, net of tax of $(13.5) and $(1.0)		(21.3	)		(1.7	)
Foreign currency translation		0.4			-
Unrealized gain on available-for-sale securities, net of tax		0.5			-
Total comprehensive income	$	27.8		$	33.1


	Nine Months Ended September 30,
(Millions)	2005			2004
Income available for common shareholders	$	138.0		$	82.0
Cash flow hedges, net of tax of $(20.5) and $5.2		(32.0	)		7.6
Foreign currency translation		0.1			-
Unrealized gain on available-for-sale securities, net of tax		0.6			-
Total comprehensive income	$	106.7		$	89.6

The following table shows the changes to Accumulated Other Comprehensive Income from December 31, 2004, to September 30, 2005.

(Millions)
December 31, 2004 balance	$	(16.1	)
Cash flow hedges		(32.0	)
Foreign currency translation adjustment		0.1
Unrealized gain on available-for-sale securities		0.6
September 30, 2005 balance	$	(47.4	)

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NOTE 15--EARNINGS PER SHARE


WPS Resources' common stock shares, $1 par value	September 30, 2005		December 31, 2004
Common stock outstanding, $1 par value, 200,000,000 shares authorized		38,091,465		37,500,791
Treasury shares		12,000		12,000
Average cost of treasury shares	$	25.19	$	25.19
Shares in deferred compensation rabbi trust		267,794		229,238
Average cost of deferred compensation rabbi trust shares	$	40.13	$	36.84

Earnings per share is computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, restricted shares, and performance share grants. The calculation of diluted earnings per share for the years shown excludes some stock option plan shares that had an anti-dilutive effect. The shares having an anti-dilutive effect are not significant for any of the periods shown. The following table reconciles the computation of basic and diluted earnings per share:


Reconciliation of Earnings Per Share	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions, except per share amounts)	2005		2004		2005		2004
Income available to common shareholders	$	48.2	$	34.8	$	138.0	$	82.0
Basic weighted average shares		38.2		37.4		38.0		37.2
Incremental issuable shares		0.4		0.2		0.3		0.3
Diluted weighted average shares		38.6		37.6		38.3		37.5
Basic earnings per common share	$	1.26	$	0.93	$	3.63	$	2.20
Diluted earnings per common share	$	1.25	$	0.93	$	3.60	$	2.19

NOTE 16--REGULATORY ENVIRONMENT

Wisconsin

On November 5, 2004, WPSC filed an application with the PSCW to defer all incremental costs, including carrying costs, resulting from unexpected problems encountered in the 2004 refueling outage at Kewaunee. During the refueling outage, an unexpected problem was encountered with equipment used for lifting the reactor vessel internal components to perform a required 10-year inspection. These equipment problems caused the outage to be extended by approximately three weeks. On November 11, 2004, the PSCW authorized WPSC to defer the replacement fuel costs related to the extended outage. On November 23, 2004, the PSCW authorized WPSC to defer purchased power costs ($5.6 million) and operating and maintenance expenses ($1.6 million) related to the extended outage, effective from when the problems were discovered, including carrying costs at WPSC's authorized weighted average cost of capital. Kewaunee returned to service on December 4, 2004. On February 18, 2005, WPSC filed for PSCW approval to recover these costs. The PSCW is reviewing the costs associated with this outage and WPSC expects these costs to be addressed in the 2006 rate case, which should be settled in December 2005.

On February 20, 2005, Kewaunee was temporarily removed from service after a potential design weakness was identified in its auxiliary feedwater system. Plant engineering staff identified the concern and the unit was shut down in accordance with the plant license. A modification was made to resolve the issue and the unit went back into service at 100% power on July 4, 2005. WPSC filed a request with the PSCW on March 11, 2005, for deferral of replacement power and operating and maintenance expenses incurred to address the design weakness and engineering issues identified. On March 17, 2005, the PSCW authorized WPSC to defer replacement fuel costs related to the outage. On April 8, 2005, the PSCW approved deferral of the operating and maintenance costs, including carrying costs at the most

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recently authorized pre-tax weighted average cost of capital. WPSC also filed with FERC for approval to defer these costs in the wholesale jurisdiction. FERC is in the process of investigating the justness and reasonableness of the recovery of the costs and will subsequently rule on the filing. For our Michigan retail customers, fuel costs are recovered through a pass through fuel adjustment clause and no deferral request is needed. Through July 4, 2005, WPSC had deferred $46.2 million of replacement power costs and $11.6 million of operating and maintenance expenses related to this outage. WPSC believes recovery of these costs in future rates is probable and anticipates the PSCW will address recovery of the deferred costs in the 2006 rate case. On July 5, 2005, WPSC sold its 59% share of Kewaunee to Dominion. See Note 5, Acquisitions and Sales of Assets, for further information on the sale of Kewaunee.

As part of the Kewaunee sale, the PSCW approved the refund of the value of the nonqualified decommissioning trust fund to customers. The details of the distribution of the refund will be addressed in the 2006 rate case. A proposal to refund the nonqualified decommissioning trust fund to customers was also approved by the FERC with no specification of the details for distribution. Subsequently, on June 7, 2005, WPSC filed with the PSCW and FERC a request for establishment of a cooperative joint proceeding for approval of the Kewaunee wind-up plan. The wind-up plan provides that the refunds to customers of the value of the nonqualified decommissioning trust fund be offset by the net loss on the sale of the plant and the Kewaunee related deferred costs applicable to each customer class. The wind-up plan also seeks to begin the amortization of the net regulatory liability as a credit to customer rates as of the effective date of the PSCW’s order (expected to be January 1, 2006). On August 8, 2005, the FERC accepted the proposed refund plan for filing and set it for hearing and settlement procedures; however, FERC denied the request for joint proceeding with the PSCW. The PSCW plans to address these issues as part of the 2006 rate case. FERC is holding a settlement discussion with WPSC in the fourth quarter of 2005.

On April 1, 2005, WPSC filed an application with the PSCW for an 11.4% increase in retail electric rates ($89.7 million in revenues) and a 2.09% increase in natural gas rates ($10.0 million in revenues), both to be effective January 1, 2006. Factors driving the requested 2006 retail electric rate increase include costs of transmission, costs for the construction of Weston 4, and increased purchased power costs. The natural gas rate increase is primarily related to increases in environmental monitoring costs and the cost of distribution system improvements. These electric amounts do not include adjustments for the nonqualified decommissioning trust fund, the loss on the sale of Kewaunee, or the Kewaunee outages, all of which are discussed above.

On October 6, 2005, WPSC updated the previously filed 2006 rate case application with the PSCW for an additional 5.7% increase ($44.6 million increase in revenues) to the electric generation fuel cost. The update to the rate case is due to the drastic increase in natural gas prices, including the effect of production and supply disruptions in the Gulf of Mexico as a result of Hurricanes Katrina and Rita. WPSC initially used 2006 natural gas futures prices from Fall 2004 to predict the 2006 cost of fuel for its natural gas-fired electric generation facilities.

The amount of fuel and purchased power costs WPSC is authorized to recover in rates is established in its PSCW general rate filings. If the actual fuel and purchased power costs vary from the authorized level by more than 2% on an annualized basis, WPSC is allowed, or may be required, to file an application adjusting rates for the remainder of the year to reflect revised annualized cost estimates. At March 31, 2005, excluding the impact of the Kewaunee outage (which was deferred), WPSC was experiencing actual fuel and purchased power costs that were more than 2% lower than the currently approved level. As a result, on April 14, 2005, the PSCW reopened WPSC's 2005 rate case for potential refund of fuel and purchased power costs. Therefore, revenues collected after that date were subject to refund pending a review of projected fuel costs for 2005. Rates would be adjusted downward for the balance of the year if projected costs were deemed to be more than 2% less than the amount allowed in the 2005 rate case. At June 30, 2005, WPSC had recorded a refund liability of $2.1 million to reflect the potential fuel refund due to customers. Subsequently, due to the drastic increase in natural gas prices, projected fuel costs for 2005 are expected to be more than 2% higher than the currently approved level, and the $2.1 million refund liability recorded in June was reversed during the third quarter of 2005.

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WPSC primarily receives coal for all of its coal-fired plants from the Power River Basin (PRB) region in Wyoming. Delivery of coal from the PRB region has been disrupted by train derailments and other operational problems purportedly caused by deteriorated rail track beds of approximately 100 miles in length in Wyoming. Repair and reconstruction of the rail line, jointly owned by BNSF Railway Co. and Union Pacific Railroad, is expected to extend until December 1, 2005 with remaining repairs completed in the Spring of 2006. Coal shipments and rail operations are expected to return to normal levels when construction activity is halted in December; however, deliveries may be delayed again in the Spring of 2006 as construction activity resumes. Reduced shipments of coal from Wyoming mines in the PRB will reduce PRB coal available for WPSC generating facilities. WPSC implemented a mitigation plan to conserve existing coal supplies and to obtain additional coal supplies from sources other than the PRB. The mitigation plan is resulting in increased incremental fuel and purchased power costs for WPSC. Therefore, on September 9, 2005, WPSC requested authorization to defer all incremental fuel and purchased power costs incurred, including carrying costs at WPSC’s most recent authorized pre-tax weighted cost of capital, as a result of the railroads’ reduction in coal deliveries and the actions taken by WPSC to manage coal supplies in this emergency situation. On September 23, 2005, the PSCW approved WPSC’s request for deferred treatment of the incremental fuel costs. As of September 30, 2005, $4.1 million was deferred.

On September 21, 2005, WPSC announced the acquisition of the Michigan and Minnesota natural gas distribution operations of Aquila, Inc. (Aquila). See Note 5, Acquisitions and Sales of Assets, for further information on the acquisition of these assets. In relation to the acquisition, WPS Michigan Utilities, Inc. and Aquila jointly filed with the MPSC on October 10, 2005, for approval of the termination of Aquila’s duty to provide natural gas service in Michigan and for WPS Michigan Utilities to provide natural gas service in the Michigan service territory of Aquila pursuant to the rates, terms, and conditions in Aquila’s current tariff book. Also in relation to the acquisition, on October 17, 2005, WPS Minnesota Utilities, Inc. and Aquila jointly filed with the Minnesota Public Utilities Commission to approve the sale of the Minnesota assets of Aquila’s two divisions, Aquila Networks-PNG and Aquila Networks-NMU, to WPS Minnesota Utilities pursuant to the Asset Purchase Agreement dated September 21, 2005. The MPSC and the Minnesota Public Utilities Commission have not yet ruled on the filings.

Michigan

On December 8, 2004, UPPCO submitted a request to the MPSC to approve UPPCO's proposed treatment of the pre-tax gains from certain sales of undeveloped and partially developed land located in the Upper Peninsula of Michigan as appropriate for ratemaking purposes. On February 4, 2005, UPPCO submitted an application to the MPSC for a 7.6% increase in retail electric rates ($5.7 million in revenues). UPPCO also requested interim rate recovery of 6.0% ($4.5 million in revenues) to allow UPPCO to recover costs during the time the MPSC is reviewing the full case. The retail electric rate increase was required due to costs associated with improving service quality and reliability, technology upgrades, and managing rising employee and retiree benefit costs. On April 28, 2005, the MPSC issued an order authorizing UPPCO to retain 100% of the pre-tax gains on certain lands owned up to $18.5 million and 73% of any pre-tax gains over that amount and UPPCO withdrew the rate increase request. In addition, UPPCO will voluntarily forego filing for retail electric service base rate increases until January 1, 2006, except UPPCO may file for MPSC consideration of deferred accounting of any governmental mandates during the moratorium and for any unusual and extraordinary events that would cause serious financial harm to UPPCO. Further, UPPCO's Power Supply Cost Recovery Clause is not subject to the filing moratorium. UPPCO intends to file a 2006 rate case with the MPSC.

Federal

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regarding the compliance filings. The application and legality of the SECA is being challenged by many load-serving entities, including ESI. On February 28, 2005, ESI filed a motion for a Partial Stay of the February 10, 2005, FERC order, proposing that SECA charges on its Michigan load be postponed until a FERC order approves a decision or settlement in the formal hearing proceeding. FERC denied this motion on May 4, 2005. On June 3, 2005, ESI filed with FERC a request for rehearing of the order denying stay. ESI also participated in a joint petition to the District of Columbia Circuit Court in an attempt to obtain a final order from the FERC on rehearing of the initial SECA order. ESI will continue to pursue all avenues to appeal and/or reduce the SECA obligations. In the interim, the exposure will be managed through customer charges and other available avenues, where feasible. Resolution of issues to be raised in the SECA hearing offer the possibility of further reductions in ESI's exposure, but the extent is unknown at present. Through existing contracts, ESI has the ability to pass a portion of the SECA charges on to customers and has begun to do so. Since SECA is a transition charge ending on March 31, 2006, it does not directly impact ESI's long-term competitiveness.

The SECA is also an issue for WPSC and UPPCO, who have intervened and protested a number of proposals in this docket because those proposals could result in unjust, unreasonable, and discriminatory charges for customers. It is anticipated that most of the SECA charges incurred by WPSC and UPPCO and any refunds will be passed on to customers through rates.

NOTE 17--SEGMENTS OF BUSINESS

We manage our reportable segments separately due to their different operating and regulatory environments. Our utility business segments are the regulated electric utility operations of WPSC and UPPCO and the regulated gas utility operations of WPSC. Our other reportable segments include two nonregulated companies, ESI and PDI. ESI is a diversified energy supply and services company. PDI is an electric generation company. The Other segment includes the operations of WPS Resources and WPS Resources Capital Corporation as holding companies, along with the nonutility activities at WPSC and UPPCO.

	Regulated Utilities							Nonutility and Nonregulated Operations
Segments of Business *(Millions)*	Electric Utility⁽¹⁾		Gas Utility⁽¹⁾			Total Utility⁽¹⁾		ESI			PDI			Other⁽¹⁾			Reconciling Eliminations			WPS Resources Consolidated

Three Months Ended September 30, 2005
External revenues	$	289.6	$	71.6		$	361.2	$	1,328.8		$	67.3		$	-		$	-		$	1,757.3
Intersegment revenues		9.0		0.2			9.2		12.1			10.5			0.3			(32.1	)		-
Income available for common shareholders		28.0		(3.5	)		24.5		8.9			13.2			1.6			-			48.2

Three Months Ended September 30, 2004
External revenues	$	233.5	$	45.5		$	279.0	$	782.4		$	30.5		$	-		$	-		$	1,091.9
Intersegment revenues		5.5		0.1			5.6		(2.9	)		8.4			0.3			(11.4	)		-
Income available for common shareholders		32.1		(3.3	)		28.8		2.5			4.2			(0.7	)		-			34.8

Nine Months Ended September 30, 2005
External revenues	$	757.9	$	335.7		$	1,093.6	$	3,338.7		$	139.4		$	-		$	-		$	4,571.7
Intersegment revenues		25.0		0.5			25.5		18.4			27.8			0.9			(72.6	)		-
Income available for common shareholders		72.4		8.6			81.0		25.3			28.7			3.0			-			138.0

Nine Months Ended September 30, 2004
External revenues	$	657.1	$	284.5		$	941.6	$	2,518.0		$	78.8		$	-		$	-		$	3,538.4
Intersegment revenues		15.6		4.3			19.9		4.3			19.7			0.9			(44.8	)		-
Income available for common shareholders		60.2		9.9			70.1		16.7			(5.0	)		0.2			-			82.0

(1) Includes only utility operations. Nonutility operations are included in the Other column.

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WPSC's principal business segments are the regulated electric utility operations and the regulated gas utility operations.

	Regulated Utilities
Segments of Business *(Millions)*	Electric Utility⁽¹⁾		Gas Utility⁽¹⁾			Total Utility		Other		Reconciling Eliminations			WPSC Consolidated

Three Months Ended September 30, 2005
External revenues	$	266.7	$	71.8		$	338.5	$	0.4	$	(0.4	)	$	338.5
Earnings on common stock		26.7		(3.5	)		23.2		2.6		(0.1	)		25.7

Three Months Ended September 30, 2004
External revenues	$	214.6	$	45.6		$	260.2	$	0.4	$	(0.4	)	$	260.2
Earnings on common stock		31.5		(3.3	)		28.2		2.3		-			30.5

Nine Months Ended September 30, 2005
External revenues	$	705.8	$	336.2		$	1,042.0	$	-	$	-		$	1,042.0
Earnings on common stock		69.7		8.6			78.3		6.3		-			84.6

Nine Months Ended September 30, 2004
External revenues	$	603.2	$	288.8		$	892.0	$	1.1	$	(1.1	)	$	892.0
Earnings on common stock		58.1		9.9			68.0		6.9		-			74.9

(1)	Includes only utility operations. Nonutility operations are included in the Other column.

NOTE 18--NEW ACCOUNTING PRONOUNCEMENTS

In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment," which addresses the accounting for share-based payment transactions. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued to Employees," and requires companies to measure the cost of share-based awards at the grant date fair value. That cost is recognized over the period during which an employee is required to provide service in exchange for the award. SFAS No. 123R will be effective for WPS Resources on January 1, 2006. SFAS No. 123R offers companies alternative methods of adopting this standard. The impact on WPS Resources' financial position and results of operations will be dependent upon a number of factors, including share-based payments made in 2006. Because we do not know the amount of share-based payments to be made in 2006, we cannot yet estimate the effect of this standard on our financial position and results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations." Interpretation No. 47 clarifies that the term Conditional Asset Retirement Obligation as used in FASB Statement No. 143, "Accounting for Asset Retirement Obligations," refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a Conditional Asset Retirement Obligation if the fair value of the liability can be reasonably estimated. WPS Resources is required to adopt the provisions of Interpretation No. 47 as of December 31, 2005. WPS Resources has not yet determined the impact that the adoption of Interpretation No. 47 will have on its financial position or results of operations. If expenses under Interpretation No. 47 for WPSC and UPPCO differ from expenses recovered currently in rates, management will assess the probability of recovering this difference in future rates. To the extent future recovery is probable, a regulatory asset would be recognized in accordance with the provisions of SFAS No. 71.

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Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION - WPS RESOURCES

WPS Resources is a holding company that is exempt from the Public Utility Holding Company Act of 1935. Our wholly owned subsidiaries include two regulated utilities, WPSC (which is an operating entity as well as a holding company exempt from the Public Utility Holding Company Act of 1935) and UPPCO. Another wholly owned subsidiary, WPS Resources Capital Corporation, is a holding company for our nonregulated businesses, including ESI and PDI.

Strategic Overview

The focal point of WPS Resources' business plan is the creation of long-term value for our shareholders (through growth, operational excellence, and asset management) and the continued emphasis on reliable, competitively priced, and environmentally sound energy services for our customers. We are seeking growth of our utility and nonregulated portfolio, but we are placing emphasis on regulated growth. A discussion of the essential components of our business plan is set forth below:

Maintain a Strong Utility Base - We are focusing on growth in our utility operations. A strong utility base is important in order to maintain quality credit ratings, which are critical to our success. WPS Resources believes the following recent events have helped or will help maintain its strong utility base:

·	In 2004, WPSC signed power sales contracts with Consolidated Water Power through December 31, 2017, and Wisconsin Public Power Inc. through April 30, 2021, in order to bolster growth beyond the normal utility growth rate.

WPSC is also expanding its generation fleet in order to meet growing electric demand and ensure the continued reliability of energy services. Construction is underway on the 500-megawatt coal-fired Weston 4 base-load power plant near Wausau, Wisconsin. WPSC also continues to pursue plans to construct other electric generating facilities, but details relating to fuel type and in-service dates have yet to be determined.

In September 2005, WPS Resources entered into a definitive agreement with Aquila, Inc. to acquire Aquila's natural gas distribution operations in Michigan and Minnesota. Subject to various regulatory approvals, these transactions are expected to close in the first half of 2006 and will more than double the size of WPS Resource's current utility natural gas business.

WPS Resources currently owns approximately 28% of ATC, which is a utility operation that owns, builds, maintains, and operates high voltage electric transmission lines primarily in Wisconsin and Upper Michigan. We continue to increase our ownership interest in the ATC through additional equity interest received as consideration for funding a portion of the Duluth, Minnesota, to Wausau, Wisconsin, transmission line.

Integrate Resources to Provide Operational Excellence - WPS Resources is committed to integrating the resources of its business units (in accordance with any applicable regulatory restrictions) by leveraging their individual capabilities and expertise across the company.

This strategy is evident at our nonregulated subsidiaries, where we have restructured the management of our two primary nonregulated subsidiaries (ESI and PDI). Currently, we have one executive management team overseeing the operations of all of our nonregulated businesses. ESI also continues to optimize the value of PDI's merchant generation fleet and reduce the market price risk while extracting additional value from these plants, through the use of various financial and physical instruments (such as forwards, futures, options, and swaps), which has provided more predictable revenues and margin.

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·	Combining resources and best practices of WPSC and the Aquila natural gas distribution businesses in Michigan and Minnesota (expected to be acquired in 2006) is expected to enhance operations of our overall natural gas distribution businesses.

Strategically Grow Nonregulated Businesses - ESI looks to grow its electric and natural gas business, targeting growth in the northeastern United States and adjacent portions of Canada (through strategic acquisitions, market penetration of existing businesses, and new product offerings), which is where ESI has the most market expertise. PDI focuses on optimizing the operational efficiency of its existing portfolio of assets and pursues compatible power development projects and the acquisition of generation assets that strategically fit with ESI's customer base and market expertise. The acquisition of Advantage Energy in July 2004 provided ESI with enhanced opportunities to compete in the New York market and had a positive impact on ESI's margin in the first half of 2005.

Place Strong Emphasis on Asset Management - Our asset management strategy calls for the continuing disposition and acquisition of assets in a manner that enhances our earnings capability. The acquisition portion of this strategy calls for the acquisition of assets that complement our existing businesses and strategy, such as the pending acquisitions of Aquila's natural gas distribution operations in Michigan and Minnesota, which are expected to be accretive to earnings (excluding one-time transition costs) over the first 12 months following the close of the acquisition, as well as ESI's 2004 acquisition of Advantage Energy. The utilities are the backbone of our earnings, and we expect ESI and PDI to continue to provide between 15 and 25 percent of our earnings in the future.

Another portion of the strategy calls for the disposition of assets, including plants and entire business units, which are no longer required for operations. The sale of Sunbury's allocated emission allowances was completed in May 2005 for $109.9 million. The proceeds received from the sale enabled Sunbury to eliminate its non-recourse debt obligation, which provided greater flexibility as PDI evaluates its options related to Sunbury. These options range from closing the plant, operating the plant only during favorable economic periods, to a future sale. We also sold WPSC's Kewaunee plant in July 2005. The major benefits of the Kewaunee sale include transferring financial risk from WPSC's electric customers and WPS Resources' shareholders to Dominion, greater certainty of future energy costs through a purchase power agreement, and being able to return the non-qualified decommissioning funds to our customers.

We also continue to evaluate alternatives for the sale of the balance of our identified real estate holdings no longer needed for operation. A significant portion of our expected land sales are at UPPCO and will benefit our customers as well as our shareholders. UPPCO withdrew a rate increase request that it filed in February 2005 after the MPSC approved its requested regulatory treatment of these land sales by sharing gains between customers and shareholders.

Business Operations

Our regulated and nonregulated businesses have distinct competencies and business strategies, offer differing products and services, experience a wide array of risks and challenges and are viewed uniquely by management. The Management's Discussion and Analysis of Financial Condition and Results of Operations - Introduction - WPS Resources appearing in the 2004 Form 10-K included a discussion of these topics. There have not been significant changes to the content of the matters discussed in the above referenced section of the 2004 Form 10-K; however, certain tables have been updated and included below to reflect current information. These tables should be read in conjunction with the discussion appearing in Management's Discussion and Analysis of Financial Condition and Results of Operations - Introduction - WPS Resources appearing in the 2004 Form 10-K.

The table below discloses future natural gas and electric sales volumes under contract at ESI as of September 30, 2005. Contracts are generally one to three years in duration. ESI expects that its ultimate sales volumes in 2005 and beyond will exceed the volumes shown in the table below as it continues to seek growth opportunities and existing customers who do not have long-term contracts continue to buy their short-term requirements from ESI.

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Forward Contracted Volumes at September 30, 2005 ⁽¹⁾	October 1, 2005 through September 30, 2006		October 1, 2006 through September 30, 2008

Wholesale sales volumes - billion cubic feet		115.8		12.3
Retail sales volumes - billion cubic feet		151.1		47.0
Total natural gas sales volumes		266.9		59.3

Wholesale sales volumes - million kilowatt-hours		10,951		4,803
Retail sales volumes - million kilowatt-hours		2,374		751
Total electric sales volumes		13,325		5,554

⁽¹⁾ This table represents physical sales contracts for natural gas and electric power for delivery or settlement in future periods; however, there is a possibility that some of the contracted volumes reflected in the above table could be net settled. Management has no reason to believe that gross margins that will be generated by the contracts included above will vary significantly from those experienced historically.

For comparative purposes, future natural gas and electric sales volumes under contract at September 30, 2004, are shown below. Actual electric and natural gas sales volumes for the nine months ended September 30, 2005, and 2004 are disclosed within Results of Operations - WPS Resources, ESI Segment Operations below.


Forward Contracted Volumes at September 30, 2004 ⁽¹⁾	October 1, 2004 through September 30, 2005		October 1, 2005 through September 30, 2007

Wholesale sales volumes - billion cubic feet		91.3		13.6
Retail sales volumes - billion cubic feet		162.9		48.9
Total natural gas sales volumes		254.2		62.5

Wholesale sales volumes - million kilowatt-hours		5,523		1,032
Retail sales volumes - million kilowatt-hours		3,730		1,832
Total electric sales volumes		9,253		2,864

⁽¹⁾ This table represents physical sales contracts for natural gas and electric power for delivery or settlement in future periods; however, there is a possibility that some of the contracted volumes reflected in the above table could be net settled. Management has no reason to believe that gross margins that will be generated by these contracts will vary significantly from those experienced historically.

The table below summarizes ESI's wholesale counterparty credit exposure, categorized by maturity date, as of September 30, 2005. At September 30, 2005, ESI had net exposure with one non-rated counterparty that was more than 10% of total exposure, including collateral. Total exposure with this counterparty was $41.2 million and is included in the table below.

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Counterparty Rating *(Millions)* ⁽¹⁾	Exposure ⁽²⁾		Exposure Less Than 1 Year		Exposure 1 to 3 Years		Exposure 4 to 5 years

Investment grade - regulated utility	$	13.7	$	13.7	$	-	$	-
Investment grade - other		305.0		223.8		76.0		5.2

Non-investment grade - regulated utility		32.2		32.2		-		-
Non-investment grade - other		4.9		4.9		-		-

Non-rated - regulated utility ⁽³⁾		-		-		-		-
Non-rated - other ⁽³⁾		97.1		85.4		10.3		1.4

Total Exposure	$	452.9	$	360.0	$	86.3	$	6.6

⁽¹⁾The investment and non-investment grade categories are determined by publicly available credit ratings of the counterparty or the rating of any guarantor, whichever is higher. Investment grade counterparties are those with a senior unsecured Moody's rating of Baa3 or above or a Standard & Poor's rating of BBB- or above.

⁽²⁾

Exposure considers netting of accounts receivable and accounts payable where netting agreements are in place as well as netting mark-to-market exposure. Exposure is before consideration of collateral from counterparties. Collateral, in the form of cash and letters of credit, received from counterparties totaled $68.4 million at September 30, 2005, $63.0 million from investment grade counterparties, and $5.4 million from non-rated counterparties.

⁽³⁾ Non-rated counterparties include stand-alone companies, as well as unrated subsidiaries of rated companies without parental credit support. These counterparties are subject to an internal credit review process.

RESULTS OF OPERATIONS - WPS RESOURCES

Third Quarter 2005 Compared with Third Quarter 2004

WPS Resources Overview

WPS Resources' results of operations for the three months ended September 30 are shown in the following table:


WPS Resources' Results (Millions, except share amounts)	2005		2004		Change

Consolidated operating revenues	$	1,757.3	$	1,091.9		60.9	%
Income available for common shareholders	$	48.2	$	34.8		38.5	%
Basic earnings per share	$	1.26	$	0.93		35.5	%
Diluted earnings per share	$	1.25	$	0.93		34.4	%

The $665.4 million increase in consolidated operating revenues for the quarter ended September 30, 2005, compared to the same quarter in 2004, was driven by a $561.4 million (72.0%) increase in revenue at ESI, an $85.8 million (30.1%) increase in utility revenue, and a $38.9 million (100.0%) increase in PDI revenue. Higher revenue at ESI was driven by an increase in natural gas prices, continued expansion of the Canadian natural gas business, and higher volumes related to an increase in structured wholesale natural gas transactions. Electric utility revenue increased $59.6 million, primarily due to higher electric sales volumes related to warmer summer weather conditions and new power sales agreements with wholesale customers, and an approved retail electric rate increase. Gas utility revenue increased $26.2 million due to an increase in the per-unit cost of natural gas, higher natural gas throughput volumes, and an approved rate increase. The increase in revenue at PDI was driven by higher revenue at Sunbury due to increased opportunities to sell power into the market due to the expiration of a fixed price outtake contract and mark-to-market gains on derivatives utilized to protect the value of a portion of PDI's Section 29 federal tax credits. Revenue changes by reportable segment are discussed in more detail below.

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Income available for common shareholders was $48.2 million ($1.26 basic earnings per share) for the quarter ended September 30, 2005, compared to $34.8 million ($0.93 basic earnings per share) for the same quarter in 2004. Significant factors impacting the change in earnings and earnings per share are as follows (and are discussed in more detail below).

PDI's earnings increased $9.0 million during the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The increase in PDI's earnings can be attributed to mark-to-market and realized gains on derivative instruments utilized to protect a portion of PDI's Section 29 federal tax credits and significant improvements in Sunbury's margin, partially offset by a decrease in Section 29 federal tax credits recognized during the quarter.

ESI's earnings increased $6.4 million, driven by a $22.1 million improvement in its natural gas margin during the quarter ended September 30, 2005, compared to the same quarter in the prior year. ESI's electric margin decreased $6.9 million, driven by lower margin from portfolio optimization strategies and lower margin from retail electric operations in Michigan. Partially offsetting the overall margin improvement was a $5.7 million increase in ESI's operating and maintenance expenses related to continued business expansion.

Utility earnings decreased $4.3 million (14.9%), largely due to the negative impact that increasing natural gas prices had on third quarter margin at the electric utility. Earnings were also negatively impacted because certain costs incurred in the third quarter of 2005 related to plant outages, carrying costs on capital additions, and other costs (which are recovered in rates relatively evenly throughout the year) were partially recovered in revenue during the first six months of the year, leading to higher earnings in those periods.

·	A $2.6 million pre-tax increase (approximately $1.6 million after taxes) in equity earnings from our investment in the ATC also contributed to the increase in income available for common shareholders.

Overview of Utility Operations

Utility operations include the electric utility segment, consisting of the electric operations of WPSC and UPPCO, and the gas utility segment, consisting of the natural gas operations of WPSC. Income available for common shareholders attributable to the electric utility segment was $28.0 million for the quarter ended September 30, 2005, compared to $32.1 million for the quarter ended September 30, 2004. The net loss attributable to the gas utility segment was $3.5 million for the quarter ended September 30, 2005, compared to a net loss of $3.3 million for the quarter ended September 30, 2004.

Electric Utility Segment Operations


WPS Resources' Electric Utility	Three Months Ended September 30,
Segment Results (Millions)	2005		2004		Change

Revenue	$	298.6	$	239.0		24.9	%
Fuel and purchased power costs		150.0		74.7		100.8	%
Margin	$	148.6	$	164.3		(9.6	%)

Sales in kilowatt-hours		4,207.4		3,730.0		12.8	%

Electric utility revenue increased $59.6 million (24.9%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. Electric utility revenue increased largely due to an increase in electric sales volumes and an approved electric rate increase for WPSC's Wisconsin retail customers. Electric sales volumes increased 12.8%, primarily due to significantly warmer weather in the third quarter of 2005, compared to the third quarter of 2004, and new power sales agreements that were

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entered into with wholesale customers. As a result of the warm weather, WPSC set all-time records for peak electric demand in the third quarter of 2005. On December 21, 2004, the PSCW approved a retail electric rate increase of $60.7 million (8.6%), effective January 1, 2005. The rate increase was required primarily to recover increased costs related to fuel and purchased power, costs related to the construction of the Weston 4 base-load generation facility, and benefit costs.

The electric utility margin decreased $15.7 million (9.6%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The decrease can be attributed to a $16.6 million (10.9%) decrease in WPSC's electric margin, which was largely driven by the sale of Kewaunee on July 5, 2005 and the related power purchase agreement. Prior to the sale of Kewaunee, only nuclear fuel expense was reported as a component of fuel and purchased power costs. Subsequent to the sale, all payments to Dominion Energy Kewaunee, LLC for power purchased from Kewaunee are reported as components of fuel and purchased power costs. These include both variable payments for energy delivered and fixed payments. As a result of the sale, WPSC no longer incurs operating and maintenance expense, depreciation and decommissioning expense, or interest expense for Kewaunee. Excluding the $21.0 million fixed payment made to Dominion Energy Kewaunee, LLC in the third quarter of 2005, the electric utility margin increased $5.3 million, compared to the same quarter in the prior year. This increase was driven by the increase in electric sales volumes and the rate increase discussed above, but was largely offset by higher per-unit fuel and purchased power costs.

The quantity of power purchased by WPSC during the quarter ended September 30, 2005, increased approximately 168% compared to the same quarter in 2004, and fuel and purchased power costs were approximately 68% higher on a per-unit basis. The increase in the quantity of power purchased was largely due to power purchased from Dominion Energy Kewaunee, LLC as previously discussed, warm weather conditions, WPSC's need to conserve coal because of coal supply issues (see Other Future Considerations), and a planned outage at WPSC's Weston 3 generation plant that began in the third quarter of 2005. The increase in the per-unit cost of fuel and purchased power was driven by the sale of Kewaunee (primarily related to $21.0 million of fixed payments being recorded as a component of fuel and purchased power costs), congestion charges and line loss charges that were not fully offset by credits from MISO, increased coal costs related to procurement of coal from alternate sources, and the need to supply more energy from higher cost peaking units due to warm weather conditions, coal conservation efforts, and a planned outage at WPSC's Weston 3 generation plant that began in the third quarter of 2005. The PSCW approved the deferral of increased fuel and purchased power costs related to the MISO and coal supply matters discussed above and WPSC deferred $15.9 million of costs related to these issues in the third quarter of 2005. Excluding deferred costs, fuel and purchased power costs at WPSC increased $68.7 million. As discussed above, approximately $21.0 million of the increase in purchased power costs related to the Kewaunee fixed payments. Excluding these fixed payments, fuel and purchased power costs at WPSC increased $47.7 million and total fuel and purchased power costs incurred during the quarter exceeded the amount recovered from ratepayers (as approved in the 2005 rate case), therefore, having a negative impact on margin.

The PSCW allows WPSC to adjust prospectively the amount billed to Wisconsin retail customers for fuel and purchased power if costs are above or below approved levels by more than 2% on an annualized basis. At June 30, 2005, WPSC was experiencing fuel and purchased power costs that were more than 2% lower than the approved level. However, primarily because of the high cost of natural gas resulting from the impact hurricanes had on natural gas supply in combination with the need to run the natural gas fired peaker units more in the third quarter, at September 30, 2005, WPSC projects that actual fuel and purchased power costs for 2005 could be significantly higher than what was allowed in the 2005 rate case.

Electric utility earnings decreased $4.1 million (12.8%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004, largely driven by the higher fuel and purchased power costs discussed above. Earnings were also negatively impacted because certain costs incurred in the third quarter of 2005 related to plant outages, carrying costs on capital additions, and other costs (which are recovered in rates relatively evenly throughout the year) were partially recovered in revenue during the first six months of the year, leading to higher earnings in those periods.

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Gas Utility Segment Operations


WPS Resources'	Three Months Ended September 30,
Gas Utility Segment Results (Millions)	2005		2004		Change

Revenue	$	71.8	$	45.6		57.5	%
Purchased natural gas costs		52.6		28.8		82.6	%
Margin	$	19.2	$	16.8		14.3	%

Throughput in therms		128.6		104.1		23.5	%

Gas utility revenue increased $26.2 million (57.5%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. Gas utility revenue increased primarily as a result of an increase in the per-unit cost of natural gas, higher natural gas throughput volumes, and a rate increase. Natural gas costs increased 15.6% (on a per-unit basis) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. Following regulatory practice, WPSC passes changes in the total cost of natural gas on to customers through a purchased gas adjustment clause, as allowed by the PSCW and the MPSC. Natural gas throughput volumes increased 23.5%, primarily related to an increase in interdepartmental sales from the natural gas utility to the electric utility as a result of increased electric generation from natural gas fired combustion turbines. The PSCW issued a final order authorizing a natural gas rate increase of $5.6 million (1.1%), effective January 1, 2005. The rate increase was primarily driven by higher benefit costs and the cost of distribution system improvements.

The natural gas utility margin increased $2.4 million (14.3%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The higher natural gas utility margin was largely due to the rate increase mentioned above. The increase in interdepartmental sales volumes to WPSC's electric utility also had a positive impact on the natural gas margin.

The gas utility realized a net loss of $3.5 million for the quarter ended September 30, 2005, compared to a net loss of $3.3 million for the quarter ended September 30, 2004. The higher net loss was attributed to an increase in operating and maintenance expenses and depreciation expense incurred by the gas utility.

Overview of Nonregulated Operations

Nonregulated operations consist of natural gas, electric, and other sales at ESI, a diversified energy supply, services, and natural gas storage company, and the operations of PDI, an electric generation company. ESI and PDI are both reportable segments.

Income available for common shareholders attributable to ESI was $8.9 million for the quarter ended September 30, 2005, compared to $2.5 million for the same quarter in 2004. The $6.4 million increase in earnings at ESI was primarily the result of higher natural gas margins.

Income available for common shareholders attributable to PDI was $13.2 million for the quarter ended September 30, 2005, compared to $4.2 million for the quarter ended September 30, 2004. PDI benefited from realized gains and mark-to-market gains on derivative instruments utilized to protect the value of a portion of PDI's Section 29 federal tax credits and improved margin from Sunbury, partially offset by a decrease in Section 29 federal tax credits recognized during the quarter.

ESI's Segment Operations

Total segment revenues at ESI were $1,340.9 million for the quarter ended September 30, 2005, compared to $779.5 million for the same quarter in 2004. The total margin at ESI was $32.3 million for the quarter ended September 30, 2005, compared to $16.9 million for the quarter ended September 30, 2004. ESI's nonregulated natural gas and electric operations are the primary contributors to revenues and margins and are discussed below.

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ESI's Natural Gas Results	Three Months Ended September 30,
(Millions, except sales volumes)	2005		2004			Change

Nonregulated natural gas revenue	$	1,153.4	$	645.2			78.8	%
Nonregulated natural gas cost of sales		1,133.1		647.0			75.1	%
Margin	$	20.3	$	(1.8	)		-

Wholesale sales in billion cubic feet ⁽¹⁾		78.4		47.3			65.8	%
Retail sales in billion cubic feet ⁽¹⁾		59.2		77.7			(23.8	%)

⁽¹⁾Represents gross physical volumes.

ESI's natural gas revenue increased $508.2 million (78.8%), driven by higher natural gas prices, continued expansion of ESI's Canadian natural gas business, and higher volumes related to an increase in structured wholesale natural gas transactions.

The natural gas margin at ESI increased $22.1 million for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The margin related to retail natural gas operations increased $12.1 million, largely due to improved management of supply for Ohio residential and commercial customers (including mark-to-market gains on options utilized to manage supply costs which expire between November 2005 and September 2006). The margin related to wholesale natural gas operations increased $10.0 million, primarily driven by the natural gas storage cycle. The natural gas storage cycle contributed $10.4 million of the increase in ESI's natural gas margin (for the quarter ended September 30, 2005, the natural gas storage cycle had a $0.6 million favorable impact on margin, compared with a $9.8 million negative impact on margin for the same period in 2004). At September 30, 2005, there was a $5.1 million difference between the market value of natural gas in storage and the market value of future sales contracts (net unrealized loss), related to the 2005/2006 natural gas storage cycle. This difference between the market value of natural gas in storage and the market value of future sales contracts related to the 2005/2006 storage cycle is expected to vary with market conditions, but will reverse entirely and have a positive impact on earnings when all of the natural gas is withdrawn from storage.


ESI's Electric Results	Three Months Ended September 30,
(Millions)	2005		2004		Change

Nonregulated electric revenue	$	186.9	$	133.9		39.6	%
Nonregulated electric cost of sales		175.5		115.6		51.8	%
Margin	$	11.4	$	18.3		(37.7	%)

Wholesale sales volumes in kilowatt-hours ⁽¹⁾		334.2		579.2		(42.3	%)
Retail sales volumes in kilowatt-hours ⁽¹⁾		1,746.5		2,027.2		(13.8	%)

⁽¹⁾Represents gross physical volumes.

ESI's electric revenue increased $53.0 million (39.6%). Higher energy market prices were partially offset by lower volumes from retail electric operations in Michigan in the third quarter of 2005.

ESI's electric margin decreased $6.9 million (37.7%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The margin attributed to wholesale electric operations decreased $6.7 million, driven primarily by a decrease in the margin contributed by portfolio optimization strategies. Period-by-period variability in the margin contributed by these activities is expected due to constantly changing market conditions and timing of gain and loss recognition on certain transactions pursuant to generally accepted accounting principles. The retail electric margin decreased $0.2 million for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004, primarily related to a $4.4 million decrease in margin from retail electric operations in Michigan, partially offset by a $3.4 million increase in margin from operations in Maine and Ohio.

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Higher transmission-related charges resulting from the Seams Elimination Charge Adjustment, which was implemented on December 1, 2004, as ordered by the FERC as part of the implementation of MISO, have negatively impacted the margin from retail electric operations in Michigan. In addition, tariff changes granted to the regulated utilities in Michigan in 2004, coupled with high wholesale energy prices, have significantly lowered the savings customers can obtain from contracting with non-utility suppliers. The tariff changes enable Michigan utilities to charge a fee to electric customers choosing non-utility suppliers in order to recover certain stranded costs. ESI has experienced some customer attrition as a result of the tariff changes and higher wholesale prices, which has negatively impacted its margin. In the third quarter of 2005, ESI realized a $2.8 million gain from the sale of power that was intended to supply customers that chose to return to utility suppliers, representing 30-40% of ESI's current Michigan load. The increase in margin in Ohio was due to improved supply pricing compared to the fixed sales price, while the favorable margin increase in Maine was due to additional load and better supply management.

PDI's Segment Operations


PDI's Operating Results	Three Months Ended September 30,
(Millions)	2005		2004		Change

Nonregulated other revenues	$	77.8	$	38.9		100.0	%
Nonregulated other cost of sales		46.2		26.9		71.7	%
Margins	$	31.6	$	12.0		163.3	%

PDI's revenue increased $38.9 million (100.0%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. A $17.8 million increase in revenue at Sunbury was primarily related to more opportunities to sell power into the market (made possible by the expiration of a fixed price outtake contract on December 31, 2004, and higher energy market prices). Sunbury's sales volumes increased approximately 14% and the price received from energy sold into the market in the third quarter of 2005 more than doubled over the price realized from sales under the fixed price outtake contract in place in 2004. A $9.0 million mark-to-market gain (net of related premium amortization), and a

$1.9 million realized gain on derivative instruments utilized to protect the value of a portion of PDI's Section 29 federal tax credits also contributed to the higher revenue. Revenue at PDI's Combined Locks Energy Center increased $6.2 million, largely due to increasing energy prices and new opportunities to sell power into the MISO market in 2005.

PDI's margin for the quarter ended September 30, 2005, increased $19.6 million (163.3%), compared to the quarter ended September 30, 2004. Mark-to-market and realized gains on derivative instruments utilized to protect the value of a portion of PDI's Section 29 federal tax credits (as discussed above) drove $10.9 million of the margin increase. Sunbury's margin improved $8.7 million (193.5%), primarily due to more opportunities to sell power into the market (discussed above). The favorable energy prices made it economical for Sunbury to operate all available solid fuel units during the third quarter of 2005.

PDI, through a subsidiary, is part owner of a synthetic fuel producing facility that generates Section 29 federal tax credits. The Section 29 federal tax credits are subject to phase out if domestic crude oil prices reach specified levels. To manage exposure to the risk that an increase in oil prices could reduce the recognizable amount of 2005, 2006, and 2007 Section 29 tax credits, PDI entered into a series of derivative contracts covering a specified number of barrels of oil. These derivatives were entered into in 2005 and mitigate approximately 100%, 95%, and 40% of the Section 29 federal tax credit exposure related to rising oil prices in 2005, 2006, and 2007, respectively. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the average New York Mercantile Exchange (NYMEX) trading price of oil in relation to the strike price of each option. The derivative contracts have not been designated as hedging instruments and, as a result, changes in the fair value of the options are recorded currently in earnings. The timing of recognizing changes in the fair value of these options likely will not correspond with the timing of when Section 29 federal tax credits are, or would have been, recognized. As of September 30, 2005, average annual oil prices for 2005 were below the level where tax credit phase out is anticipated to occur.

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Overview of Holding Company and Other Segment Operations

Holding Company and Other operations include the operations of WPS Resources and WPS Resources Capital as holding companies and the nonutility activities of WPSC and UPPCO. Holding Company and Other operations had earnings of $1.6 million during the quarter ended September 30, 2005, compared to a net loss of $0.7 million during the same period in 2004. A $2.6 million increase in equity earnings from ATC drove the increase in earnings. Pre-tax equity earnings from ATC were $6.6 million for the quarter ended September 30, 2005, compared to $4.0 million for the quarter ended September 30, 2004.

Operating Expenses


	Three Months Ended September 30,
WPS Resources' Operating Expenses (Millions)	2005		2004		Change

Operating and maintenance expense	$	124.0	$	123.9		-	%
Depreciation and decommissioning expense		23.8		26.1		(8.8	%)
Taxes other than income		11.8		11.5		2.6	%

Operating and Maintenance Expense

Overall, operating and maintenance expenses did not change significantly for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. WPSC's operating and maintenance expenses decreased $6.7 million, driven by a $10.0 million decrease related to Kewaunee. WPSC sold its 59% interest in Kewaunee to Dominion Energy Kewaunee, LLC on July 5, 2005, and currently purchases 59% of the output from this facility through a power purchase agreement. The decrease in operating and maintenance expenses as a result of the Kewaunee sale, were partially offset by increases in transmission costs and pension and postretirement expense. Operating expenses at ESI increased $5.7 million, primarily due to higher payroll, benefits, and other costs related to continued business expansion. PDI's operating and maintenance expenses increased $2.8 million, primarily related to costs incurred to repair damaged compressor blades at PDI's Syracuse generation facility in New York. Operating and maintenance expenses related to Holding Company and Other Segment operations decreased $1.2 million, driven by a decrease in legal and consulting expenses.

Depreciation and Decommissioning Expense

Depreciation and decommissioning expense decreased $2.3 million (8.8%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004, driven by a $3.1 million decrease in depreciation expense resulting from the sale of Kewaunee in July 2005 and lower gains on decommissioning trust assets, partially offset by additional depreciation due to continued capital investment. Realized gains on decommissioning trust assets are partially offset by decommissioning expense pursuant to regulatory practice.

Other Income (Expense)


	Three Months Ended September 30,
WPS Resources' Other Income (Expense) (Millions)	2005			2004			Change

Miscellaneous income	$	9.6		$	9.9			(3.0	%)
Interest expense		(15.6	)		(14.9	)		4.7	%
Minority interest		1.2			1.2			-	%
Other income (expense)	$	(4.8	)	$	(3.8	)		26.3	%

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Miscellaneous Income

Miscellaneous income decreased $0.3 million (3.0%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The decrease in miscellaneous income was driven by a $1.4 million higher loss recognized by PDI from its investments in a synthetic fuel producing facility and a decrease in realized gains on the nonqualified nuclear decommissioning trust assets due to the liquidation of the decommissioning trust assets in the second quarter of 2005 as a result of the Kewaunee sale. The increased loss related to the synthetic fuel producing facility was driven by more production being allocated to PDI's subsidiary (ECO Coal Pelletization #12 LLC) in the third quarter of 2005 compared to the same period in 2004 and an increase in the cost of fuel produced from this facility. These decreases were partially offset by a $2.6 million increase in equity earnings from ATC.

Interest Expense

Interest expense increased $0.7 million (4.7%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The increase in interest expense was primarily related to an increase in the average amount of short-term debt outstanding during the third quarter of 2005, compared to the third quarter of 2004. While average short-term debt levels increased, primarily to fund capital expenditures related to the Weston 4 base-load plant and the Wausau, Wisconsin, to Duluth, Minnesota transmission line, short-term debt was reduced significantly in the third quarter of 2005 due to proceeds received from the sale of Kewaunee.

Provision for Income Taxes

The effective tax rate was 27.2% for the quarter ended September 30, 2005, compared to 20.8% for the quarter ended September 30, 2004. The increase in the effective tax rate was driven by higher income before taxes recognized in the third quarter of 2005, compared to the third quarter of 2004, in combination with a decrease in Section 29 federal tax credits recognized.

Generally accepted accounting principles require our year-to-date interim effective tax rate to reflect our projected annual effective tax rate. As a result, we estimate the effective tax rate for the year and, based upon year-to-date pre-tax earnings, record tax expense for the period to reflect the projected annual effective tax rate. Therefore, although Section 29 federal tax credits are produced approximately ratably throughout the year, the amount of credits reflected in the tax provision for the quarter ended September 30, 2005, was based upon the projected annual effective tax rate and year-to-date pre-tax earnings.

Our ownership interest in the synthetic fuel operation resulted in recognizing the tax benefit of Section 29 federal tax credits totaling $5.5 million for the quarter ended September 30, 2005, and $7.1 million for the quarter ended September 30, 2004. As noted above, the amount of Section 29 federal tax credits recognized is based upon the estimated annual effective tax rate and is not necessarily reflective of tax credits produced during the period. For the year ending December 31, 2005, we expect to recognize the benefit of Section 29 federal tax credits totaling approximately $25.7 million. For the year ended December 31, 2004, we recognized the benefit of Section 29 federal tax credits totaling $27.8 million.

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Nine Months 2005 Compared with Nine Months 2004

WPS Resources Overview

WPS Resources' results of operations for the nine months ended September 30 are shown in the following table:


WPS Resources' Results (Millions, except share amounts)	2005		2004		Change

Consolidated operating revenues	$	4,571.7	$	3,538.4		29.2	%
Income available for common shareholders	$	138.0	$	82.0		68.3	%
Basic earnings per share	$	3.63	$	2.20		65.0	%
Diluted earnings per share	$	3.60	$	2.19		64.4	%

The $1,033.3 million increase in consolidated operating revenues for the nine months ended September 30, 2005, compared to the same period in 2004, was largely driven by an $834.8 million (33.1%) increase in revenue at ESI and a $157.6 million (16.4%) increase in utility revenue. Higher revenue at ESI was driven by an increase in natural gas prices, continued expansion of the Canadian natural gas business, and higher volumes related to an increase in structured wholesale natural gas transactions. Electric utility revenue increased $110.2 million (16.4%), primarily due to an approved retail electric rate increase, and higher electric sales volumes related to warmer summer weather conditions and new power sales agreements with wholesale customers. Gas utility revenue increased $47.4 million due primarily to an increase in the per-unit cost of natural gas, an approved rate increase, and higher natural gas throughput volumes. Revenue changes by reportable segment are discussed in more detail below.

Income available for common shareholders was $138.0 million ($3.63 basic earnings per share) for the nine months ended September 30, 2005, compared to $82.0 million ($2.20 basic earnings per share) for the nine months ended September 30, 2004. Significant factors impacting the change in earnings and earnings per share are as follows (and are discussed in more detail below).

PDI realized earnings of $28.7 million for the nine months ended September 30, 2005, compared to a net loss of $5.0 million for the same period in 2004, which correlates to a $33.7 million increase in earnings at PDI. PDI' s margin increased $45.2 million, largely due to a $25.2 million improvement in Sunbury's margin, and a combination of mark-to-market and realized gains on certain derivative instruments utilized to protect the value of a portion of PDI's Section 29 federal tax credits. PDI also benefited from an $8.2 million increase in Section 29 federal tax credits recognized during the nine months ended September 30, 2005, compared to the same period in the prior year. PDI's operating results were negatively impacted by an $80.6 million pre-tax impairment loss that was required to write down Sunbury's assets to fair market value and the recognition of $9.1 million of interest expense related to the termination of Sunbury's interest rate swap; however, these losses were substantially offset by an $86.8 million pre-tax gain recognized on the sale of Sunbury's allocated emission allowances.

Warmer temperatures during the cooling season in 2005, compared to 2004, and a retail electric rate increase favorably impacted WPSC's electric margin, contributing to a $12.2 million increase in electric utility earnings; however, the increase in electric utility earnings at WPSC was partially offset in the third quarter of 2005 by rising natural gas prices.

ESI's earnings increased $8.6 million (51.5%), driven by a $30.3 million increase in natural gas margin, primarily related to natural gas operations in Ohio. ESI's electric margin decreased $9.2 million, driven by lower margins from retail electric operations in Michigan. Partially offsetting the overall margin improvement was a $7.1 million increase in ESI's operating and maintenance expenses related to continued business expansion.

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·	A $6.2 million pre-tax increase in equity earnings (approximately $3.7 million after taxes) from our investment in the ATC also contributed to the increase in income available for common shareholders.

Overview of Utility Operations

Income available for common shareholders attributable to the electric utility segment was $72.4 million for the nine months ended September 30, 2005, compared to $60.2 million for the nine months ended September 30, 2004. Income available for common shareholders attributable to the gas utility segment was $8.6 million for the nine months ended September 30, 2005, compared to $9.9 million for the nine months ended September 30, 2004.

Electric Utility Segment Operations


WPS Resources' Electric Utility	Nine Months Ended September 30,
Segment Results (Millions)	2005		2004		Change

Revenue	$	782.9	$	672.7		16.4	%
Fuel and purchased power costs		309.9		216.9		42.9	%
Margin	$	473.0	$	455.8		3.8	%

Sales in kilowatt-hours		11,691.1		10,792.0		8.3	%

Electric utility revenue increased $110.2 million (16.4%) for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. Electric utility revenue increased largely due to an approved electric rate increase for WPSC's Wisconsin retail customers and an increase in electric sales volumes. On December 21, 2004, the PSCW approved a retail electric rate increase of $60.7 million (8.6%), effective January 1, 2005. Electric sales volumes increased 8.3%, primarily due to significantly warmer weather during the second and third quarters of 2005, compared to the same periods in 2004, and new power sales agreements that were entered into with wholesale customers. As a result of the warm weather, both WPSC and UPPCO set all-time records for peak electric demand in the second and third quarters of 2005.

The electric utility margin increased $17.2 million (3.8%) for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. WPSC's electric margin increased

$16.7 million ($37.7 million if the $21.0 million fixed payment made for power purchased from Dominion Energy Kewaunee, LLC in the third quarter of 2005 was excluded), which was primarily driven by the retail electric rate increase and the increase in electric sales volumes discussed above.

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matters, and WPSC deferred $16.3 million of costs related to these issues during the nine months ended September 30, 2005. Excluding deferred costs, fuel and purchased power costs at WPSC increased $85.9 million for the nine months ended September 30, 2005, compared to the same period in 2004, primarily related to the significant increase in natural gas prices after the hurricanes disrupted natural gas supply. As discussed above, approximately $21.0 million of the increase in purchased power costs related to the Kewaunee fixed payments. Excluding these fixed payments, fuel and purchased power costs at WPSC increased $64.9 million and total fuel and purchased power costs incurred during the nine months ended September 30, 2005, exceeded the amount recovered from ratepayers (as approved in the 2005 rate case) and, therefore, had a negative impact on margin.

Gas Utility Segment Operations


WPS Resources'	Nine Months Ended September 30,
Gas Utility Segment Results (Millions)	2005		2004		Change

Revenue	$	336.2	$	288.8		16.4	%
Purchased natural gas costs		247.1		203.4		21.5	%
Margin	$	89.1	$	85.4		4.3	%

Throughput in therms		599.9		571.1		5.0	%

Gas utility revenue increased $47.4 million (16.4%) for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. Gas utility revenue increased primarily as a result of an increase in the per-unit cost of natural gas, a natural gas rate increase, and higher natural gas throughput volumes. Natural gas costs increased 12.5% (on a per-unit basis) for the nine months ended September 30, 2005, compared to the same period in 2004. The PSCW issued a final order authorizing a natural gas rate increase of $5.6 million (1.1%), effective January 1, 2005. Natural gas throughput volumes increased 5.0%, primarily related to an increase in interdepartmental sales from the natural gas utility to the electric utility as a result of increased generation from combustion turbines. The combustion turbines were dispatched more often due to the Kewaunee outage, warm weather conditions, and coal conservation efforts. Higher natural gas throughput volumes from interdepartmental sales to the electric utility were partially offset by lower natural gas throughput volumes to residential customers, related primarily to milder weather in the first half of 2005, compared to the same period in 2004.

The natural gas utility margin increased $3.7 million (4.3%) for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. The higher natural gas utility margin was largely due to the rate increase mentioned above. The increase in interdepartmental sales volumes to WPSC's electric utility also had a positive impact on the natural gas margin.

Income available for common shareholders attributed to the gas utility decreased $1.3 million (13.1%). The higher margin was more than offset by an increase in operating and maintenance expenses at the gas utility.

Overview of Nonregulated Operations

Income available for common shareholders attributable to ESI was $25.3 million for the nine months ended September 30, 2005, compared to $16.7 million for the same period in 2004. The $8.6 million increase in earnings at ESI was primarily the result of higher natural gas margins.

Income available for common shareholders attributable to PDI was $28.7 million for the nine months ended September 30, 2005, compared to a net loss of $5.0 million for the same period in 2004. The

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earnings improvement was largely due to margin improvements (discussed below). PDI also benefited from an increase in Section 29 federal tax credits recognized for the nine months ended September 30, 2005, compared to the same period in 2004. PDI's operating results were negatively impacted by an $80.6 million pre-tax impairment loss that was required to write down Sunbury's long-lived assets to fair market value and the recognition of $9.1 million in interest expense related to the termination of Sunbury's interest rate swap; however, these losses were substantially offset by an $86.8 million pre-tax gain recognized on the sale of Sunbury's allocated emission allowances.

ESI's Segment Operations

Total segment revenues at ESI were $3,357.1 million for the nine months ended September 30, 2005, compared to $2,522.3 million for the same period in 2004. The total margin at ESI was $90.2 million for the nine months ended September 30, 2005, compared to $68.7 million for the nine months ended September 30, 2004. ESI's nonregulated natural gas and electric operations are the primary contributors to revenues and margins and are discussed below.


ESI's Natural Gas Results	Nine Months Ended September 30,
(Millions, except sales volumes)	2005		2004		Change

Nonregulated natural gas revenue	$	2,947.1	$	2,126.5		38.6	%
Nonregulated natural gas cost of sales		2,893.1		2,102.8		37.6	%
Margin	$	54.0	$	23.7		127.8	%

Wholesale sales in billion cubic feet ⁽¹⁾		195.0		174.4		11.8	%
Retail sales in billion cubic feet ⁽¹⁾		202.5		222.1		(8.8	%)

⁽¹⁾Represents gross physical volumes.

ESI's natural gas revenue increased $820.6 million (38.6%), driven by higher natural gas prices, continued expansion of ESI's Canadian natural gas business, and higher volumes related to an increase in structured wholesale natural gas transactions.

The natural gas margin at ESI increased $30.3 million (127.8%) for the nine months ended September 30, 2005, compared to the same period in 2004. The margin related to retail natural gas operations increased $19.5 million, largely due to improved management of supply for Ohio residential and commercial customers (including mark-to-market gains on options utilized to manage supply costs which expire between November 2005 and September 2006), and new customers in Ohio. The margin related to wholesale natural gas operations increased $10.8 million, driven primarily by results of the natural gas storage cycle and a $3.3 million favorable settlement with a counterparty. The natural gas storage cycle had a $5.0 million positive impact on ESI's natural gas margin (for the nine months ended September 30, 2005, the natural gas storage cycle had a $4.4 million negative impact on margin, compared with a $9.4 million negative impact on margin for the same period in 2004). The remaining increase was related to higher margin from structured wholesale natural gas transactions (the profitability and volume of these products were higher due to the increased variability in the price of natural gas during the nine months ended September 30, 2005, compared to the same period in 2004).

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ESI's Electric Results	Nine Months Ended September 30,
(Millions)	2005		2004		Change

Nonregulated electric revenue	$	408.0	$	394.1		3.5	%
Nonregulated electric cost of sales		373.8		350.7		6.6	%
Margin	$	34.2	$	43.4		(21.2	%)

Wholesale sales volumes in kilowatt-hours ⁽¹⁾		723.4		2,796.1		(74.1	%)
Retail sales volumes in kilowatt-hours ⁽¹⁾		5,142.2		5,237.9		(1.8	%)

⁽¹⁾Represents gross physical volumes.

ESI's electric revenue increased $13.9 million (3.5%). Increased revenue from the July 2004 acquisition of Advantage Energy and higher energy market prices were partially offset by a decrease in wholesale electric sales volumes related to ESI's prior participation in the New Jersey Basic Generation Services Program, which ended on May 31, 2004, and lower sales volumes from retail electric operations in Michigan during 2005.

ESI's electric margin decreased $9.2 million (21.2%) for the nine months ended September 30, 2005, compared to the same period in 2004. The retail electric margin decreased $5.5 million for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004, driven by a $12.6 million decrease in margin from retail electric operations in Michigan. The decrease in margin related to retail electric operations in Michigan was partially offset by positive operating results from Advantage Energy and an increase in margin from operations in Maine and Ohio. Higher transmission-related charges resulting from the Seams Elimination Charge Adjustment, which was implemented on December 1, 2004, as ordered by the FERC as part of the implementation of the MISO, have negatively impacted the margin from retail electric operations in Michigan. In addition, tariff changes granted to the regulated utilities in Michigan in 2004, coupled with high wholesale energy prices, have significantly lowered the savings customers can obtain from contracting with non-utility suppliers. The tariff changes enable Michigan utilities to charge a fee to electric customers choosing non-utility suppliers in order to recover certain stranded costs. ESI has experienced some customer attrition as a result of the tariff changes and higher wholesale energy prices, which has negatively impacted its margin. In the third quarter of 2005, ESI realized a $2.8 million gain from the sale of power that was intended to supply customers that chose to return to utility suppliers, representing 30-40% of ESI's current Michigan load. The increase in margin in Ohio was due to improved supply pricing compared to the fixed sales price, while the margin increase in Maine was due to additional load and better supply management. The margin attributed to wholesale electric operations decreased $3.7 million, driven primarily by a decrease in the margin contributed by portfolio optimization strategies. Period-by-period variability in the margin contributed by these activities is expected due to constantly changing market conditions and timing of gain and loss recognition on certain transactions pursuant to generally accepted accounting principles.

PDI's Segment Operations


PDI's Operating Results	Nine Months Ended September 30,
(Millions)	2005		2004		Change

Nonregulated other revenues	$	167.2	$	98.5		69.7	%
Nonregulated other cost of sales		98.9		75.4		31.2	%
Margins	$	68.3	$	23.1		195.7	%

PDI's revenue increased $68.7 million (69.7%) for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. A $28.4 million (60.8%) increase in revenue at Sunbury was primarily related to more opportunities to sell power into the market (made possible by the expiration of a fixed price outtake contract on December 31, 2004, and higher energy market prices). Sunbury's sales volumes were flat over the prior year; however, the average price received from energy sold into the market for the nine months ended September 30, 2005, was $62.55 per megawatt-hour, compared to an

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average price received from energy sold into the market of $48.39 per megawatt-hour for the nine months ended September 30, 2004, and an average selling price of $26.96 per megawatt-hour to the counterparty under the fixed price outtake contract for the nine months ended September 30, 2004. A $12.9 million mark-to-market gain (net of related premium amortization) and a $1.9 million realized gain on derivative instruments utilized to protect the value of a portion of PDI's Section 29 federal tax credits also contributed to the higher revenue. Revenue at PDI's Combined Locks Energy Center in Wisconsin increased $10.2 million, largely due to increasing energy prices and new opportunities to sell power into the MISO market in 2005. A combined $11.2 million increase in revenue was realized at PDI's steam boiler in Oregon and its Stoneman generating facility in Wisconsin. The increase in revenue from the steam boiler in Oregon was driven by higher demand for energy from the steam customer at this facility and an increase in the price of energy sold. Revenue at the Stoneman generating facility increased as a result of a two-year power sales agreement that was entered into in the second quarter of 2004.

PDI's margin for the nine months ended September 30, 2005, increased $45.2 million (195.7%), compared to the same period in 2004. Sunbury's margin improved $25.2 million (427.1%), primarily due to more opportunities to sell power into the market (discussed above). Mark-to-market and realized gains on derivative instruments utilized to protect the value of a portion of PDI's Section 29 federal tax credits drove $14.8 million of the margin increase. Higher contracted selling prices benefited PDI's Niagara facility in New York and its Westwood facility in Pennsylvania, resulting in a combined $3.8 million margin increase at these facilities.

Overview of Holding Company and Other Segment Operations

Holding Company and Other operations had earnings of $3.0 million during the nine months ended September 30, 2005, compared to $0.2 million during the nine months ended September 30, 2004. The increase in earnings was driven by an increase in equity earnings from ATC and $1.5 million of deferred financing costs that were written off in the first quarter of 2004. Pre-tax equity earnings from ATC were $17.7 million for the nine months ended September 30, 2005, compared to $11.5 million for the nine months ended September 30, 2004. These increases were partially offset by a $1.4 million decrease in equity earnings from Wisconsin River Power Company (resulting from fewer land sales for the nine months ended September 30, 2005) and $1.2 million of increased interest costs and deferred financing fees related to restructuring Sunbury's debt to a WPS Resources' obligation in June 2005.

Operating Expenses


	Nine Months Ended September 30,
WPS Resources' Operating Expenses (Millions)	2005			2004		Change

Operating and maintenance expense	$	399.4		$	394.1		1.3	%
Depreciation and decommissioning expense		119.6			78.4		52.6	%
Gain on sales of emission allowances		(86.8	)		-		-
Impairment loss		80.6			-		-
Taxes other than income		35.7			34.8		2.6	%

Operating and Maintenance Expense

Operating and maintenance expenses increased $5.3 million (1.3%) for the nine months ended September 30, 2005, compared to the same period in 2004. Utility operating and maintenance expenses decreased $3.2 million, primarily related to a $2.5 million decrease at WPSC. The decrease in operating and maintenance expense at WPSC was driven by a $10.0 million decrease related to Kewaunee in the third quarter of 2005, compared to the third quarter of 2004. WPSC sold its 59% interest in Kewaunee to Dominion Energy Kewaunee, LLC on July 5, 2005, and currently purchases 59% of the output of this facility from Dominion Energy Kewaunee, LLC through a power purchase agreement. The decrease in operating and maintenance expenses as a result of the Kewaunee sale, was partially offset by increases in transmission costs and pension and postretirement expense. The unplanned outage at Kewaunee earlier in 2005 did not significantly impact the period-over-period change in operating and maintenance

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expenses as the PSCW approved the deferral of incremental operating and maintenance expenses that were incurred as a direct result of the unplanned outage. Operating and maintenance costs of $11.6 million were deferred during the nine months ended September 30, 2005, related to this outage. Operating expenses at ESI increased $7.1 million, primarily due to higher payroll, benefits, and other costs related to continued business expansion. Operating and maintenance expenses at PDI increased $3.1 million, driven by a $1.9 million increase in operating and maintenance expense at PDI's Syracuse generation facility in New York related to costs incurred to repair damaged compressor blades, and a $0.7 million write-down of spare parts inventory at Sunbury in the second quarter of 2005. Operating expenses related to Holding Company and Other Segment operations decreased $1.3 million, driven by a decrease in legal and consulting expenses.

Depreciation and Decommissioning Expense

Depreciation and decommissioning expense increased $41.2 million (52.6%) for the nine months ended September 30, 2005, compared to the same period in 2004, largely due to an increase of $40.3 million at WPSC. Approximately $38 million of the increase resulted from increased gains on decommissioning trust assets prior to the sale of Kewaunee. The remaining increase related to continued capital investment, partially offset by a decrease in depreciation that resulted from the sale of the Kewaunee assets in July 2005. Realized gains on decommissioning trust assets were partially offset by decommissioning expense pursuant to regulatory practice (see the detailed discussion in Miscellaneous Income below).

Gain on Sale of Emission Allowances

PDI completed the sale of Sunbury's allocated emission allowances in May 2005. The sales proceeds were $109.9 million, resulting in a pre-tax gain of $85.9 million. PDI also sold a small amount of Sunbury's emission allowances in the first quarter of 2005, recognizing a pre-tax gain of $0.9 million. For more information on Sunbury, see Note 4, Assets Held for Sale, to Condensed Notes to Financial Statements.

Impairment Loss

The sale of Sunbury's allocated emission allowances in May 2005, provided PDI with more time to evaluate various options related to Sunbury. These options range from closing the plant, retaining the plant and operating it during favorable economic periods, or a future sale. Because WPS Resources is no longer committed to the sale of Sunbury as its only option, generally accepted accounting principles require all long-lived assets that were previously classified as held for sale to be reclassified as held and used at the lower of their carrying value before they were classified as held for sale adjusted for depreciation that would have been recognized had the assets been continuously classified as held and used, or fair value at the date the held for sale criteria was no longer met. Upon reclassification of the Sunbury plant and related assets as held and used in the second quarter of 2005, PDI recorded a non-cash, pre-tax impairment charge of $80.6 million. The impairment charge reflects the reduction in the fair value of the Sunbury plant without the related emission allowances. For more information on Sunbury, see Note 4, Assets Held for Sale, to Condensed Notes to Financial Statements.

Other Income (Expense)


	Nine Months Ended September 30,
WPS Resources' Other Income (Expense) (Millions)	2005			2004			Change

Miscellaneous income	$	62.8		$	20.8			201.9	%
Interest expense		(56.2	)		(44.2	)		27.1	%
Minority interest		3.4			2.3			47.8	%
Other income (expense)	$	10.0		$	(21.1	)		-

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Miscellaneous Income

Miscellaneous income increased $42.0 million for the nine months ended September 30, 2005, compared to the same period in 2004. Approximately $38 million of the increase in miscellaneous income related to realized gains on the nonqualified nuclear decommissioning trust assets. The nonqualified decommissioning trust assets were placed in more conservative investments in the second quarter of 2005 in anticipation of the sale of Kewaunee, which was completed on July 5, 2005. Pursuant to regulatory practice, the increase in miscellaneous income related to the realized gains was offset by an increase in decommissioning expense. Overall, the change in the investment strategy for the nonqualified decommissioning trust assets had no impact on income available for common shareholders. An increase of $6.2 million in equity earnings from WPS Resources' investment in ATC and a $1.5 million write-off in the first quarter of 2004 of previously deferred financing costs associated with the redemption of the trust preferred securities also contributed to the increase in miscellaneous income. The increases were partially offset by a $2.6 million higher loss recognized by PDI from its investments in a synthetic fuel producing facility and a $1.4 million decrease in equity earnings from Wisconsin River Power Company (resulting from fewer land sales during the nine months ended September 30, 2005, compared to the same period in 2004). The increased loss related to the synthetic fuel producing facility was driven by more production being allocated to PDI's subsidiary (ECO Coal Pelletization #12 LLC) for the nine months ended September 30, 2005, compared to the same period in 2004 and an increase in the cost of fuel produced from this facility.

Interest Expense

Interest expense increased $12.0 million (27.1%) for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. The increase in interest expense was primarily related to terminating the interest rate swap pertaining to Sunbury's non-recourse debt obligation in the second quarter of 2005. The interest rate swap was previously designated as a cash flow hedge and, as a result, the mark-to-market losses were recorded as a component of other comprehensive income. WPS Resources is required to recognize the amount accumulated within other comprehensive income as a component of interest expense when the hedged transactions (future interest payments on debt) are no longer probable of occurring. As a result, the restructuring of the Sunbury non-recourse debt to a WPS Resources' obligation in June 2005 triggered the recognition of $9.1 million of interest expense related to the mark-to-market value of the swap at the date of restructuring. The remaining increase in interest expense was primarily related to an increase in the average level of short-term debt outstanding during the nine months ended September 30, 2005, compared to the same period in 2004.

Minority Interest

The increase in minority interest occurred because the minority owner of PDI's subsidiary, ECO Coal Pelletization #12 LLC, was not allocated any production from the synthetic fuel facility for the quarter ended March 31, 2004.

Provision for Income Taxes

The effective tax rate was 23.0% for the nine months ended September 30, 2005, compared to 19.9% for the nine months ended September 30, 2004. Although more tax credits were recognized during the nine months ended September 30, 2005, compared to the same period in 2004, the effective tax rate increased as a result of a 73.2% increase in income before taxes.

Generally accepted accounting principles require our year-to-date interim effective tax rate to reflect our projected annual effective tax rate. As a result, we estimate the effective tax rate for the year and, based upon year-to-date pre-tax earnings, record tax expense for the period to reflect the projected annual effective tax rate. Therefore, although Section 29 federal tax credits are produced approximately ratably throughout the year, the amount of credits reflected in the tax provision for the nine months ended September 30, 2005, and 2004, was based upon the projected annual effective tax rate and year-to-date pre-tax earnings.

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Our ownership interest in the synthetic fuel operation resulted in recognizing the tax benefit of Section 29 federal tax credits totaling $24.1 million for the nine months ended September 30, 2005, and $15.9 million for the nine months ended September 30, 2004. As noted above, the amount of Section 29 federal tax credits recognized is based upon the estimated annual effective tax rate and is not necessarily reflective of tax credits produced during the period. For the year ending December 31, 2005, we expect to recognize the benefit of Section 29 federal tax credits totaling approximately $25.7 million. For the year ended December 31, 2004, we recognized the benefit of Section 29 federal tax credits totaling $27.8 million.

LIQUIDITY AND CAPITAL RESOURCES - WPS RESOURCES

We believe that our cash balances, liquid assets, operating cash flows, access to equity capital markets, and borrowing capacity made available because of strong credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. However, our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside of our control. In addition, our borrowing costs can be impacted by short- and long-term debt ratings assigned by independent rating agencies. Currently, we believe our credit ratings are among the best in the energy industry (see the Financing Cash Flows, Credit Ratings section below).

Operating Cash Flows

During the nine months ended September 30, 2005, net cash provided by operating activities was $172.4 million, compared with $259.3 million during the nine months ended September 30, 2004. The decrease was driven by changes in working capital, mostly at ESI. Lower wholesale sales volumes at ESI in the fourth quarter of 2004, compared to the fourth quarter of 2003, resulted in lower receivable balances to be collected in 2005, compared to 2004. In addition, more favorable natural gas storage opportunities in 2005 resulted in higher inventory levels for ESI at September 30, 2005, compared to September 30, 2004.

Investing Cash Flows

Net cash provided by investing activities was $11.1 million during the nine months ended September 30, 2005, compared to $209.9 million used for investing activities during the nine months ended September 30, 2004. The change is primarily due to proceeds of $112.5 million and $127.1 million received from the sale of Kewaunee and the liquidation of the related non-qualified decommissioning trust, respectively, along with $110.9 million of proceeds from the sale of Sunbury's emission allowances. These proceeds were partially offset by an increase in capital expenditures of $94.3 million (mostly related to WPSC), as well as increased contributions to ATC.

During the first nine months of 2005, WPS Resources invested $35.4 million in ATC, compared to $18.0 million in the first nine months of 2004. This increased WPS Resources' consolidated ownership interest in ATC to approximately 28%. WPS Resources contributed $12.6 million of capital to ECO Coal Pelletization #12 in the first nine months of 2005 compared to $12.0 million in the first nine months of 2004.

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Capital Expenditures

Capital expenditures by business segment for the nine months ended September 30 are as follows:


(Millions)	2005		2004

Electric utility	$	264.6	$	144.6
Gas utility		25.2		47.6
ESI		0.1		1.2
PDI		2.9		3.4
Other		0.9		2.6
WPS Resources consolidated	$	293.7	$	199.4

The increase in capital expenditures at the electric utility for the nine months ended September 30, 2005, as compared to the same period in 2004, is mainly due to higher capital expenditures associated with the construction of Weston 4. Gas utility capital expenditures decreased primarily due to the completion of the automated meter-reading project.

Dairyland Power Cooperative has confirmed its intent to purchase an interest in Weston 4, subject to a number of conditions. If the purchase is completed, electric utility expenditures made by WPSC for Weston 4 will be reduced by 30 percent. The agreement with Dairyland Power Cooperative is part of our continuing plan to provide least-cost, reliable energy for the increasing electric demand of our customers and to reduce risk. We expect to close on this transaction by the end of 2005.

Financing Cash Flows

Net cash used for financing activities was $196.1 million during the nine months ended September 30, 2005, compared to $45.0 million during the nine months ended September 30, 2004. The increase is attributed to increased repayments of commercial paper in 2005, partially offset by the repayment of long-term debt in 2004 using the proceeds from a 2003 issuance of common stock at WPS Resources.

Significant Financing Activities

WPS Resources had $138.0 million in outstanding commercial paper borrowings at September 30, 2005, compared to $130.9 million in outstanding commercial paper borrowings at September 30, 2004. WPS Resources had other outstanding short-term debt of $10.0 million and $12.7 million as of September 30, 2005, and 2004, respectively.

In 2005 and 2004, we issued new shares of common stock under our Stock Investment Plan and under certain stock-based employee benefit and compensation plans. As a result of these plans, equity increased $26.1 million and $22.3 million in the nine months ended September 30, 2005, and 2004, respectively. WPS Resources did not repurchase any existing common stock during the nine months ended September 30, 2005, or 2004.

On June 17, 2005, $62.9 million of non-recourse debt at a PDI subsidiary that was used to finance the purchase of Sunbury was converted to a five-year WPS Resources obligation in connection with the sale of Sunbury's allocated emission allowances. An additional $2.7 million drawn on a line of credit at PDI was rolled into the five-year WPS Resources obligation. The floating interest rate on the total five-year WPS Resources obligation of $65.6 million has been fixed at 4.595% through two interest rate swaps.

On January 19, 2004, WPSC retired $49.9 million of its 7.125% series first mortgage bonds. These bonds had an original maturity date of July 1, 2023.

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On January 8, 2004, WPS Resources retired $50.0 million of its 7.0% trust preferred securities. As a result of this transaction, WPSR Capital Trust I, a Delaware business trust, was dissolved.

Credit Ratings

WPS Resources and WPSC use internally generated funds and commercial paper borrowings to satisfy most of their capital requirements. WPS Resources also periodically issues long-term debt and common stock to reduce short-term debt, maintain desired capitalization ratios, and fund future growth. WPS Resources may seek nonrecourse financing for funding nonregulated acquisitions. WPS Resources' commercial paper borrowing program provides for working capital requirements of the nonregulated businesses and UPPCO. WPSC has its own commercial paper borrowing program. WPSC also periodically issues long-term debt, receives equity contributions from WPS Resources, and makes payments for return of capital to WPS Resources to reduce short-term debt, fund future growth, and maintain capitalization ratios as authorized by the PSCW. The specific forms of long-term financing, amounts, and timing depend on the availability of projects, market conditions, and other factors.

The current credit ratings for WPS Resources and WPSC are listed in the table below.


Credit Ratings	Standard & Poor's	Moody's
WPS Resources Senior unsecured debt Commercial paper Credit facility	A A-1 -	A1 P-1 A1
WPSC Senior secured debt Preferred stock Commercial paper Credit facility	A+ A- A-1 -	Aa2 A2 P-1 Aa3

In January 2005, Standard & Poor's downgraded its ratings for WPSC one level to the rating identified above and established a negative outlook. At the same time, Standard & Poor's affirmed WPS Resources' ratings but changed the outlook from stable to negative. In taking these actions, Standard & Poor's cited WPSC's substantial capital spending program and the risk profile of WPS Resources' nonregulated businesses.

In September 2005, Standard & Poor’s placed all of WPS Resources’ and WPSC’s credit ratings on CreditWatch with negative implications as a result of WPS Resources’ announcement that it entered into a definitive agreement with Aquila, Inc. to acquire Aquila's natural gas distribution operations in Michigan and Minnesota. Although Standard & Poor’s noted that WPS Resources’ business risk profile could be strengthened with the inclusion of the additional natural gas distribution utilities, they will not remove the CreditWatch with negative implications until meeting with the company to assess the assets to be acquired, better understand the integration strategy, and review a new financial forecast that incorporates the two proposed natural gas acquisitions.

Similarly, in September 2005, Moody’s announced no change to the current ratings, but changed the rating outlook for WPS Resources and WPSC from stable to negative, citing a potential risk that the company’s leverage may increase over the next several years.

Still, we believe these ratings continue to be among the best in the energy industry and allow us to access commercial paper and long-term debt markets on favorable terms. Credit ratings are not recommendations to buy, are subject to change, and each rating should be evaluated independently of any other rating.

Rating agencies use a number of both quantitative and qualitative measures in determining a company's credit rating. These measures include, but are not limited to, business risk, liquidity risk, competitive

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position, capital mix, financial condition, predictability of cash flows, management strength, and future direction. Some of the quantitative measures can be analyzed through a few key financial ratios, while the qualitative measures are more subjective.

WPS Resources and WPSC hold credit lines to back 100% of their commercial paper borrowing and letters of credit. These credit facilities are based on a credit rating of A-1/P-1 for WPS Resources' commercial paper and A-1/P-1 for WPSC's commercial paper. A significant decrease in the commercial paper credit ratings could adversely affect the companies by increasing the interest rates at which they can borrow and potentially limiting their access to funds through the commercial paper market. A restriction in the companies' ability to use commercial paper borrowing to meet working capital needs would require them to secure funds through alternate sources resulting in higher interest expense, higher credit line fees, and a potential delay in the availability of funds.

ESI maintains underlying agreements to support its electric and natural gas operations. In the event of a deterioration of WPS Resources' credit rating, many of these agreements allow the counterparty to demand additional assurance of payment. This provision could pertain to existing business, new business, or both with the counterparty. The additional assurance requirements could be met with letters of credit, surety bonds, or cash deposits and would likely result in WPS Resources being required to maintain increased bank lines of credit or incur additional expenses, and could restrict the amount of business ESI can conduct.

ESI uses the NYMEX and over-the-counter financial markets to hedge its exposure to physical customer obligations. These hedges are closely correlated to the customer contracts, but price movements on the hedge contracts may require financial backing. Certain movements in price for contracts through the NYMEX exchange require posting of cash deposits equal to the market move. For the over-the-counter market, the underlying contract may allow the counterparty to require additional collateral to cover the net financial differential between the original contract price and the current forward market. Increased requirements related to market price changes usually result in a temporary liquidity need that will unwind as the sales contracts are fulfilled.

Future Capital Requirements and Resources

Contractual Obligations

The following table summarizes the contractual obligations of WPS Resources, including its subsidiaries.


			Payments Due By Period
Contractual Obligations As of September 30, 2005 (Millions)	Total Amounts Committed		Less Than 1 Year		1 to 3 Years		3 to 5 Years		Over 5 Years

Long-term debt principal and interest payments	$	1,276.2	$	28.1	$	111.0	$	262.0	$	875.1
Operating leases		23.9		1.4		7.5		5.8		9.2
Commodity purchase obligations		6,188.3		1,601.8		3,091.7		577.7		917.1
Purchase orders		485.7		270.4		184.4		30.9		-
Capital contributions to equity method investment		168.7		27.6		134.1		7.0		-
Other		419.0		30.6		89.6		49.7		249.1
Total contractual cash obligations	$	8,561.8	$	1,959.9	$	3,618.3	$	933.1	$	2,050.5

Long-term debt principal and interest payments represent bonds issued, notes issued, and loans made to WPS Resources and its subsidiaries. We record all principal obligations on the balance sheet. Commodity purchase obligations represent mainly commodity purchase contracts of WPS Resources and its subsidiaries. Energy supply contracts at ESI included as part of commodity purchase obligations are generally entered into to meet obligations to deliver energy to customers. WPSC and UPPCO expect to

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recover the costs of their contracts in future customer rates. Purchase orders include obligations related to normal business operations and large construction obligations, including 100% of Weston 4 obligations; however, we expect 30% of these costs to be paid by Dairyland Power Cooperative after the close of Dairyland’s purchase of 30% of Weston 4, which is expected to close late in the year. Included in the purchase orders listed in the table above, is $301.2 million related to Weston 4 purchase obligations. Capital contributions to equity method investment include our commitment to fund a portion of the Wausau, Wisconsin, to Duluth, Minnesota, transmission line. The table above does not reflect obligations under the definitive agreement with Aquila, Inc. to acquire Aquila’s natural gas distribution operations in Michigan and Minnesota. Other mainly represents expected pension and postretirement funding obligations.

Capital Requirements

WPSC makes large investments in capital assets. Net construction expenditures are expected to be approximately $1.0 billion in the aggregate for the 2005 through 2007 period. The largest of these expenditures is for the construction of Weston 4, for which WPSC is expected to incur costs of $419 million between 2005 through 2007, assuming 70% ownership after the expected purchase of a 30% interest in Weston 4 by Dairyland Power Cooperative.

As part of its regulated utility operations, on September 26, 2003, WPSC submitted an application for a Certificate of Public Convenience and Necessity to the PSCW seeking approval to construct Weston 4, a 500-megawatt coal-fired generation facility near Wausau, Wisconsin. The facility is estimated to cost approximately $779 million (including the acquisition of coal trains), of which WPSC will be responsible for 70% assuming Dairyland Power Cooperative purchases their expected 30% interest in Weston 4. Through September 30, 2005, WPSC has incurred a total cost of $295 million related to this project. In addition, WPSC expects to incur additional construction costs through the date the plant goes into service of about $75 million to fund construction of the transmission facilities required to support Weston 4. ATC will reimburse WPSC for the construction costs of the transmission facilities and related carrying costs when Weston 4 becomes commercially operational, which is expected to occur in June 2008.

On October 7, 2004, we received the final PSCW order granting authority to proceed with construction of Weston 4, contingent upon receipt of an air permit. The air permit was issued by the WDNR on October 19, 2004. We believe the air permit is one of the most stringent in the nation, which means that Weston 4 will be one of the cleanest plants of its kind in the United States. Construction began in October 2004. On November 15, 2004, a petition was filed with the WDNR contesting the air permit issued. On December 2, 2004, the WDNR granted the petition and forwarded the matter to the Division of Hearings and Appeals. Construction continues, and a contested case hearing on the air permit was held in September 2005. A decision from the Administrative Law Judge is expected in January 2006.

Other significant anticipated expenditures during this three-year period (2005 through 2007) include:

·	mercury and pollution control projects - $84 million

·	corporate services infrastructures - $34 million

On April 18, 2003, the PSCW approved WPSC's request to transfer its interest in the Wausau, Wisconsin, to Duluth, Minnesota, transmission line to the ATC. WPS Resources committed to fund 50% of total project costs incurred up to $198 million, and receive additional equity in the ATC in exchange for the project funding. WPS Resources may terminate funding if the project extends beyond January 1, 2010. On December 19, 2003, WPSC and ATC received approval to continue the project at a revised cost estimate of $420.3 million to reflect additional costs for the project resulting from time delays, added regulatory requirements, changes and additions to the project, and ATC overhead costs. The final portion of the line is expected to be placed in service in 2008. WPS Resources has the right, but not the obligation, to provide additional funding in excess of $198 million up to 50% of the revised cost estimate. Allete, Inc. has an option to fund a portion of this commitment and intends to fund $60 million by the end of 2006. This would ultimately decrease the amount of additional equity WPS Resources has in the ATC. For the period 2005 through 2009, WPS Resources expects to fund up to approximately $176 million for

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its portion of the Wausau to Duluth transmission line assuming Allete, Inc. does not exercise its option, and approximately $116 million if Allete does exercise its option. The $176 million of capital contributions includes approximately $35 million of contributions made to the ATC in the first nine months of 2005.

WPS Resources expects to provide additional capital contributions to ATC of approximately $53 million for the period 2005 through 2007 for other projects, assuming Allete does not exercise its option. If Allete does exercise its option, this amount will be reduced to $46 million.

UPPCO is expected to incur construction expenditures of about $49 million in the aggregate for the period 2005 through 2007, primarily for electric distribution improvements and repairs and safety measures at hydroelectric facilities.

Capital expenditures identified at PDI for 2005 through 2007 are expected to be approximately $3 million.

Capital expenditures identified at ESI for 2005 through 2007 are expected to be approximately $8 million, largely due to expenditures related to Advantage Energy, computer equipment related to business expansion and normal technology upgrades.

All projected capital and investment expenditures are subject to periodic review and revision and may vary significantly from the estimates depending on a number of factors, including, but not limited to, industry restructuring, regulatory constraints, acquisition opportunities, market volatility, and economic trends. Other capital expenditures for WPS Resources and its subsidiaries for 2005 through 2007 could be significant depending on its success in pursuing development and acquisition opportunities. When appropriate, WPS Resources may seek nonrecourse financing for a portion of the cost of these acquisitions.

Capital Resources

As of September 30, 2005, both WPS Resources and WPSC were in compliance with all of the covenants under their lines of credit and other debt obligations.

For the period 2005 through 2007, WPS Resources plans to use internally generated funds net of forecasted dividend payments, cash proceeds from asset sales, and debt and equity financings to fund capital requirements. WPS Resources plans to maintain current debt to equity ratios at appropriate levels to support current credit ratings and corporate growth. Management believes WPS Resources has adequate financial flexibility and resources to meet its future needs.

WPS Resources has the ability to issue up to $450.0 million of debt and equity under its currently effective shelf registration statement. WPSC has the ability to issue up to an additional $375.0 million of debt under its currently effective shelf registration statements.

On June 2, 2005, WPS Resources entered into an unsecured $500 million 5-year credit agreement. This revolving credit line replaces the former 364-day credit line facilities, which had a borrowing capacity of $400 million. WPSC also entered into a new 5-year credit facility, for $115 million, to replace its former 364-day credit line facility for the same amount. The credit lines are used to back 100% of WPS Resources' and WPSC's commercial paper borrowing programs and the majority of letters of credit for WPS Resources and WPSC. As of September 30, 2005, there was a total of $404.5 million and $79.2 million available under WPS Resources' and WPSC's credit lines, respectively.

In May 2005, PDI entered into transactions with multiple counterparties to sell the allocated emission allowances associated with Sunbury. In July 2005, WPSC sold its portion of Kewaunee. A portion of the proceeds from the Kewaunee sale was used to retire short-term debt at WPSC. The remainder of the proceeds from the sale of both the Sunbury emissions allowances and Kewaunee will be used by WPS Resources for investing activities and general corporate purposes of its subsidiaries, including reducing the amount of outstanding debt. For more information regarding these sales, see the discussion below under Other Future Considerations.

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WPS Resources intends to sign bridge credit agreements of $557.5 million and $300 million in early November 2005. The bridge facilities are intended to backup commercial paper borrowing related to the purchase of the Michigan and Minnesota natural gas distribution operations from Aquila and to support purchase price adjustments related to working capital at the time of the closing of the transactions. The capacity under the bridge facilities will be reduced by the amount of proceeds from any long-term financing we complete prior to closing, with the exception of proceeds from a common stock sale scheduled to occur prior to signing the purchase agreements. The credit agreements will be further reduced as permanent or replacement financing is secured at the time of closing the transactions, and will expire by September 2007. The bridge credit agreements have representations and covenants that are similar to those in our existing credit facilities.

WPS Resources plans to permanently finance the acquisition of the Michigan and Minnesota natural gas distribution operations from Aquila with a combination of debt and equity.

Other Future Considerations

Agreement to Purchase Aquila's Michigan and Minnesota Natural Gas Distribution Operations

On September 21, 2005, WPS Resources, through wholly owned subsidiaries, entered into two definitive agreements with Aquila Inc. to acquire Aquila's natural gas distribution operations in Michigan and Minnesota for approximately $558 million, exclusive of direct costs of the acquisition. The purchase price also excludes certain adjustments related to working capital, including accounts receivable, unbilled revenue, inventory, and certain other current assets. The purchase price is also subject to certain other closing and post-closing adjustments, primarily net plant adjustments.

WPS Resources plans that permanent financing for the acquisition will be raised through the issuance of a combination of equity and long-term debt.

Excluding one-time integration costs, the transaction is expected to be accretive to WPS Resources' earnings over the first 12 months following the close of the acquisition. WPS Resources anticipates maintaining its current dividend policy following the closing.

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Sunbury

WPS Resources made capital contributions of $1.0 million to Sunbury during the first nine months of 2005. In 2004, WPS Resources made capital contributions of $24.5 million to Sunbury, all during the first nine months of 2004. Contributions made in the first nine months of 2005 were necessary to meet certain working capital requirements. In 2004, WPS Resources' Board of Directors granted authorization to contribute up to $32.8 million of capital to Sunbury. At September 30, 2005, $7.3 million of the originally authorized amount remains available for contribution. Financial results for Sunbury have improved in 2005, compared to 2004, primarily due to more opportunities to sell power into the market as the result of the expiration of a fixed price outtake contract on December 31, 2004. Current energy market prices are significantly higher than the fixed price received under the expired contract.

The sale of Sunbury's allocated emission allowances was completed in May 2005. Total sales proceeds of $109.9 million were utilized by Sunbury to eliminate its nonrecourse debt obligation, which provided PDI with flexibility to consider various alternatives for the plant. All available solid fuel units at the Sunbury plant were operated through September 30, 2005, due to favorable market conditions. Should market conditions decline, PDI will consider placing the plant in a stand-by mode of operation, which will serve to minimize future operating expenses while maintaining several options for the plant (including closing the plant, retaining the plant and operating it during favorable economic periods, or a potential future sale of the plant). Dispatching Sunbury in a stand-by mode of operation will help focus production on higher-priced periods, generally in the winter and mid-summer months. The success of a stand-by mode of operation will depend on Sunbury's ability to minimize costs during non-operating periods. Current projections show Sunbury dispatching and achieving positive cash flows for the remainder of the year; therefore, it appears that the authorized level of capital available to meet the cash flow needs of Sunbury is sufficient through 2005.

Kewaunee

In early July 2005, Kewaunee returned to service following an unplanned outage that began in February 2005. As approved by the PSCW and FERC, WPSC deferred outage costs associated with incremental fuel, purchased power, and operating and maintenance costs.

On July 5, 2005, WPSC completed the sale of its 59% ownership interest in Kewaunee to a subsidiary of Dominion Resources, Inc. At the same time, Wisconsin Power and Light Company sold its 41% ownership interest to Dominion. The major benefits of the sale for WPSC included shifting financial risk from utility customers and shareholders to Dominion, greater certainty of future costs, and the return of nonqualified decommissioning funds to customers.

WPSC's share of the cash proceeds from the sale was $112.5 million. Dominion received the assets in WPSC's qualified decommissioning trust and assumed responsibility for the eventual decommissioning of Kewaunee. These trust assets had a pre-tax fair value of $243.6 million at closing. WPSC retained ownership of the assets contained in its nonqualified decommissioning trust. The sale of Kewaunee resulted in a loss of $12.1 million, which equals the proceeds from the sale less the net assets sold, adjusted by several additional items. The most significant of these adjustments is the fair value of an indemnity issued to cover certain costs Dominion may incur related to the recent unplanned outage. In addition, the adjustments included certain costs related to the termination of the plant operating agreement and withdrawal from WPS Resources' investment in the Nuclear Management Company ("NMC"), which served as the licensed operator of Kewaunee. WPSC has received approval from the PSCW for deferral of the loss resulting from this transaction and related costs. WPSC has proposed that proceeds of $127.1 million received from the liquidation of the nonqualified decommissioning trust assets be refunded to customers, net of the loss on the sale of the plant assets and costs related to the 2004 and 2005 Kewaunee outages.

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Beaver Falls

PDI's Beaver Falls generation facility in New York has been out of service since late June 2005. An unplanned outage was caused by the failure of the first stage turbine blades. At this time, inclusive of estimated insurance recoveries, PDI estimates that it will cost between $3 and $5 million to repair the turbine and replace the damaged blades. If the estimated repair costs are subsequently revised upward or the repair costs are not fully recoverable through insurance, then a possibility exists that the repairs either will not be made or will cause the undiscounted cash flows related to future operations to be insufficient to recover the carrying value of the plant, resulting in an impairment. The carrying value of the Beaver Falls generation facility at September 30, 2005 is $18.6 million.

Asset Management Strategy

WPS Resources is finalizing its sales strategy for the balance of its identified real estate holdings no longer needed for operations.

Regulatory

For a discussion of regulatory considerations, see Note 16, Regulatory Environment.

Industry Restructuring

-Ohio-

In May 1999, the Ohio Legislature passed Senate Bill 3, which introduced market-based rates and instituted competitive retail electric services. The bill also established a market development period beginning January 1, 2001, and extending no later than December 31, 2005, after which rates would be set at market-based prices. During this market development period, ESI had contracted to be the supplier for approximately 100,000 residential, small commercial, and government facilities in the FirstEnergy service areas under the State of Ohio provisions for Opt-out Electric Aggregation Programs.

The Public Utilities Commission of Ohio requested the Ohio electric distribution utilities to file rate stabilization plans covering the 2006-2008 time period to avoid rate shock at the end of the market development period. A plan submitted by FirstEnergy establishes electric rates for consumers beginning in 2006 if a competitive bid auction ordered by the Public Utilities Commission of Ohio does not produce better benefits. The price resulting from an auction conducted on December 8, 2004, was inadequate. Because the FirstEnergy plan is priced lower than current market power prices, ESI will discontinue service to customers of the existing aggregation programs after the expiration of those contracts in December 2005. For 2006, the loss of these customers is estimated to have a $3.8 million negative impact on ESI's gross margin.

On September 23, 2004, an Ohio House Bill was introduced, proposing change to the electric restructuring law. The bill proposes to give the Public Utilities Commission of Ohio explicit authority to implement rate stabilization plans in certain circumstances. Recent news releases indicate an increased momentum in the Ohio General Assembly for legislation that would make major changes to Senate Bill 3 in 2005.

The Ohio Senate held meetings during March 2005 to hear from all parties involved as they develop a statewide energy policy (natural gas and electric). The Senate heard and considered such issues as rolling back Senate Bill 3, pushing ahead with electric deregulation, and the need for rate-based utility construction of new power plants in the state. In addition to the electric issues, the Senate also heard about natural gas issues. ESI participated and testified, urging the Senate to move forward to implement a competitive environment. If the regulatory climate and market allow, ESI may bring electric power market opportunities to Ohio communities for 2007.

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-Michigan-

Under the current Electric Choice program in Michigan, ESI, through its Michigan subsidiary, has established itself as a significant supplier to the industrial and commercial markets. However, recent high wholesale energy prices coupled with both approved and pending tariff changes for the regulated utilities have significantly lowered the savings customers can obtain from contracting with non-utility suppliers. As a result, many customers have returned to the bundled tariff service of the incumbent utility. The high wholesale energy prices and tariff changes have caused a reduction in new business and renewals for ESI, decreasing contracted demand levels from a high of approximately 900 megawatts to a current level of 465 megawatts. The MPSC is expected to provide orders in two significant proceedings by the end of the year that will clarify the outlook for Electric Choice.

The status of Michigan's electric markets has been the subject of hearings in both the Senate and House Energy Committees. However, no new legislation has been proposed to date. The Senate bills that were introduced in 2004 contained provisions that would have substantially harmed the Electric Choice market and returned Michigan to a model of the regulated supply monopoly. If similar legislation is proposed and passed, it could diminish the benefits of competitive supply for Michigan business customers. The impact on ESI could range from maintaining Michigan business with little or no growth to an inability to re-contract any business, leading to a possible decision by ESI to exit Michigan's electric market and redirect resources to more vibrant markets. It is not unreasonable to expect changes, either from the legislature or the MPSC, that will have some level of negative impact on ESI, but it is unlikely that Michigan customers will lose all of the benefits of competition and revert back to a fully regulated monopoly supply. ESI is actively participating in the legislative and regulatory process in order to protect its interests in Michigan.

-Midwest Independent Transmission System Operator-

WPSC, UPPCO, and ESI are members of the Midwest Independent Transmission System Operator (MISO), which introduced its "Day 2" energy markets on April 1, 2005, when it began centrally dispatching wholesale electricity along with providing transmission service throughout much of the Midwest. The new market is based on a locational marginal pricing system, which is similar to that used by the successful PJM regional transmission organization. The pricing mechanism expands the existing market from a physical market to also include financial implications and is intended to send price signals to stakeholders where generation or transmission system expansion is needed. This methodology is consistent with and responsive to the FERC direction over the past four years to develop a standard competitive generation market. Based upon the early results of the transition, it does not appear that the new market will have a material ongoing impact on the financial results of WPS Resources. WPS Resources will continue to work closely with the MISO and the FERC to ensure that any issues are dealt with such that the financial impact continues to be minimal. WPSC has been granted approval by the PSCW to defer costs and benefits related to the new market for inclusion in future rates for its Wisconsin retail electric customers. Costs and benefits related to WPSC's and UPPCO's Michigan and wholesale electric customers will also flow through fuel adjustment mechanisms.

Although the market is running well so far, there are still market issues that must be resolved. MISO "Day 2" has the potential to significantly impact the cost of transmission for eastern Wisconsin and the Upper Peninsula of Michigan system, including WPSC and UPPCO, as well as our marketing affiliates in the MISO footprint, such as ESI. Under this market-based approach, where there is abundant transmission capacity, overall costs should be less due to the ability to access cheaper generation from across the MISO footprint. For areas with narrowly constrained transmission capacity, such as Wisconsin and the Upper Peninsula of Michigan, costs could be higher due to the congestion and marginal loss pricing components. For the utilities in eastern Wisconsin and the Upper Peninsula of Michigan, mechanisms have been deployed to offset these potential increased costs in the first five years of the "Day 2" market. If the market works appropriately, the costs to ESI, excluding the Seams Elimination Charge Adjustment (discussed below), should be similar to the pre-"Day 2" market costs. If there are incremental costs or savings to WPSC and UPPCO, they would be passed through to our customers under existing tariffs.

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WPSC has established an energy market risk policy and a risk management plan to facilitate utilization of financial instruments for managing market risks associated with the "Day 2" energy market. The PSCW has approved this plan, allowing WPSC to pass the costs and benefits of several specific risk management strategies through the PSCW's fuel rules, deferral, or escrow processes.

Seams Elimination Charge Adjustment

Through a series of orders issued by FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they will no longer receive due to this elimination, the FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) to be put into place. Load-serving entities will pay these SECA charges during a 16-month transition period from December 1, 2004, through March 31, 2006. ESI is a load-serving entity and will be billed based on its power imports into MISO from PJM during 2002 and 2003. Total exposure for the 16-month transitional period, taken from proposed compliance filings by the transmission owners, is approximately $19.2 million total for ESI, of which $17.4 million is for Michigan and $1.8 million is for Ohio. Through September 30, 2005, ESI has made payments totaling $10.2 million for these charges, of which $7.6 million has been expensed.

On February 10, 2005, the FERC issued an order requesting compliance filings from transmission providers implementing the SECA effective December 1, 2004, subject to refund and surcharge, as appropriate. Public hearings will be held regarding the compliance filings. The application and legality of the SECA is being challenged by many load-serving entities, including ESI. On February 28, 2005, ESI filed a motion for a Partial Stay of the February 10, 2005, FERC order, proposing that SECA charges on its Michigan load be postponed until a FERC order approves a decision or settlement in the formal hearing proceeding. The FERC denied this motion on May 4, 2005. On June 3, 2005, ESI filed with FERC a request for rehearing of the order denying stay. ESI also participated in a joint petition to the District of Columbia Circuit Court in an attempt to obtain a final order from the FERC on rehearing of the initial SECA order. In the interim, the exposure will be managed through customer charges and other available avenues, where feasible. It is probable that ESI's total exposure will be reduced by up to $4.8 million because of inconsistencies between the FERC's SECA order and the transmission owners' compliance filings (upon which current obligations are based). Resolution of issues to be raised in the SECA hearing offer the possibility of further reductions in ESI's exposure, but the extent is unknown at present. Through existing contracts, ESI has the ability to pass a portion of the SECA charges on to customers and has begun to do so. Since SECA is a transition charge ending on March 31, 2006, it does not directly impact ESI's long-term competitiveness.

The SECA is also an issue for WPSC and UPPCO, who have intervened and protested a number of proposals in this docket because those proposals could result in unjust, unreasonable, and discriminatory charges for electric customers. It is anticipated that most of the SECA charges incurred by WPSC and UPPCO and any refunds will be passed through customer rates.

Coal Supply

In May 2005, WPSC received notification from its coal transportation suppliers that extensive maintenance is required on the railroad tracks that lead into and out of the Powder River Basin. The notification stated that the maintenance efforts were expected to result in a 15-20% reduction in the amount of contracted deliveries of Powder River Basin coal to certain of WPSC's coal generating facilities through November 2005. Actual coal deliveries in the third quarter were approximately 15% below the level of deliveries originally contracted. As a result of the notification and subsequent reduction in coal deliveries, WPSC has continued to take steps to conserve coal usage and has secured some alternative coal supplies at its affected generation facilities. Although WPSC believes it has minimized and will continue to minimize the adverse impact on its fuel and purchased power costs, the conservation efforts reduced the capacity factors of the coal generating units, requiring WPSC to generate power from higher cost units and to purchase power through other higher cost generating resources in the MISO. At this

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time, WPSC does not expect the coal shortages to have a significant impact on earnings as costs related to this matter have been approved for deferral by the PSCW.

Income Taxes

-American Jobs Creation Act of 2004-

On October 22, 2004, the President of the United States signed into law the American Jobs Creation Act of 2004 ("2004 Jobs Act"). The 2004 Jobs Act introduces a new tax deduction, the "United States production activities deduction." This domestic production provision allows as a deduction an amount equal to a specified percent of the lesser of the qualified production activities income of the taxpayer for the taxable year or taxable income for the taxable year. The deduction is phased in, providing a deduction of three percent of income through 2006, six percent of income through 2009, and nine percent of income after 2009. On December 21, 2004, the FASB issued staff position ("FSP") 109-1, effective the same day, on accounting for the effects of the domestic production deduction provisions. FSP 109-1 said the deduction should be accounted for as a special deduction rather than a tax rate reduction. FSP 109-1 also said the special deduction should be considered by an enterprise in measuring deferred taxes when graduated tax rates are a significant factor and also in assessing whether a valuation allowance is necessary. On December 8, 2004, the PSCW issued an order authorizing WPSC to defer the revenue requirements impacts resulting from the 2004 Jobs Act. The Internal Revenue Service and Department of Treasury issued interim guidance on January 19, 2005, covering the implementation of the domestic production provision of the 2004 Jobs Act. WPSC has recorded the estimated tax impact of this deduction in its financial statements for the nine months ended September 30, 2005. However, pursuant to regulatory treatment, the majority of the tax benefits derived were deferred and will be passed on to customers in future rates.

-Section 29 Federal Tax Credits-

We have significantly reduced our consolidated federal income tax liability for the past four years through tax credits available to us under Section 29 of the Internal Revenue Code for the production and sale of solid synthetic fuel from coal. These tax credits are scheduled to expire at the end of 2007 and are provided as an incentive for taxpayers to produce fuels from alternate sources and reduce domestic dependence on imported oil. This incentive is not deemed necessary if the price of oil increases sufficiently to provide a natural market for these fuels. Therefore, the tax credit in a given year is subject to phase out if the reference price of oil within that year exceeds a threshold price set by the IRS and is eliminated entirely if the reference price increases beyond a phase-out price. The reference price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. The threshold price at which the credit begins to phase out was set in 1980 and is adjusted annually for inflation; the IRS releases the final numbers for a given year in the first part of the following year. For 2004, the reference price was $36.75, the threshold price was $51.35, and the credits would have been eliminated had the reference price exceeded $64.47. For 2005, the estimated threshold price is $52.57, and the credits will be eliminated if the reference price exceeds $65.99.

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options), all of which are recorded in Risk management assets on the balance sheet and will be amortized over the applicable periods. The derivative contracts have not been designated as hedging instruments and, as a result, changes in the fair value of the options are recorded currently in earnings. As of September 30, 2005, unrealized pre-tax mark-to-market gains of $5.3 million, $5.7 million, and $4.4 million were recorded for the 2005, 2006, and 2007 options, respectively, and a $1.9 million gain was realized related to the 2005 contracts.

-Peshtigo River Land Donation-

In 2004, WPS Resources submitted a request to have the Internal Revenue Service conduct a pre-filing review of a tax position related to the 2004 tax return. The tax position related to the value of the Peshtigo River land donated to the WDNR in 2004. A pre-filing review of the land donation deduction was initiated by the Internal Revenue Service in the first quarter of 2005; however, in the second quarter, WPS Resources and the Internal Revenue Service mutually agreed to withdraw this issue from the pre-filing review process, citing an inability to reach a consensus on the tax treatment and value of the land donated. In 2004, WPS Resources recorded a $4.1 million income tax benefit related to the Peshtigo River land donation. We believe the value we placed on the land donated was reasonable and will continue to pursue this matter if challenged by the Internal Revenue Service upon examination of the tax return.

GUARANTEES AND OFF BALANCE SHEET ARRANGEMENTS - WPS RESOURCES

As part of normal business, WPS Resources and its subsidiaries enter into various guarantees providing financial or performance assurance to third parties on behalf of certain subsidiaries. These guarantees are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes.

The guarantees issued by WPS Resources include inter-company guarantees between parents and their subsidiaries, which are eliminated in consolidation, and guarantees of the subsidiaries' own performance. As such, these guarantees are excluded from the recognition, measurement, and disclosure requirements of FIN No. 45, "Guarantors' Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others."

At September 30, 2005, and December 31, 2004, outstanding guarantees totaled $1,182.7 million and $977.9 million, respectively, as follows:


WPS Resources' Outstanding Guarantees (Millions)	September 30, 2005		December 31, 2004
Guarantees of subsidiary debt	$	27.2	$	27.2
Guarantees supporting commodity transactions of subsidiaries		1,073.9		863.9
Standby letters of credit		76.0		80.9
Surety bonds		0.7		0.6
Other guarantee		4.9		5.3
Total guarantees	$	1,182.7	$	977.9

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WPS Resources' Outstanding Guarantees (Millions) Commitments Expiring	Total Amounts Committed At September 30, 2005		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Over 5 Years
Guarantees of subsidiary debt	$	27.2	$	-	$	-	$	-	$	27.2
Guarantees supporting commodity transactions of subsidiaries		1,073.9		896.5		118.2		15.2		44.0
Standby letters of credit		76.0		60.4		15.6		-		-
Surety bonds		0.7		0.7		.		-		-
Other guarantee		4.9		-		-		4.9		-
Total guarantees	$	1,182.7	$	957.6	$	133.8	$	20.1	$	71.2

At September 30, 2005, WPS Resources had outstanding $27.2 million in corporate guarantees supporting indebtedness. Of that total, $27.0 million supports outstanding debt at one of PDI's subsidiaries. The underlying debt related to these guarantees is reflected on the Condensed Consolidated Balance Sheet.

At September 30, 2005, WPS Resources' Board of Directors had authorized management to issue corporate guarantees in the aggregate amount of up to $1.2 billion to support the business operations of ESI and PDI. On October 27, 2005, WPS Resources' Board of Directors authorized an additional $150 million of corporate guarantees to support the business operations of ESI and PDI bringing the aggregate amount to $1.35 billion. WPS Resources primarily issues guarantees for indemnification obligations related to business purchase agreements and to counterparties in the wholesale electric and natural gas marketplace to provide counterparties the assurance that ESI and PDI will perform on their obligations and permit ESI and PDI to operate within these markets. At September 30, 2005, WPS Resources provided parental guarantees in the amount of $1,068.9 million, reflected in the above table, for ESI's and PDI's indemnification obligations for business operations, including $8.1 million of guarantees that received specific authorization from WPS Resources' Board of Directors and are not included in the $1.2 billion general authorized amount. Of the parental guarantees provided by WPS Resources, the outstanding balance at September 30, 2005, which WPS Resources would be obligated to support is $261 million.

Another $5.0 million of corporate guarantees support energy and transmission supply at UPPCO. In February 2005, WPS Resources' Board of Directors authorized management to issue corporate guarantees in the aggregate amount of up to $15.0 million to support the business operations of UPPCO. Corporate guarantees issued in the future under the Board authorized limit may or may not be reflected on WPS Resources' Condensed Consolidated Balance Sheet, depending on the nature of the guarantee.

At WPS Resources' request, financial institutions have issued $76.0 million in standby letters of credit for the benefit of third parties that have extended credit to certain subsidiaries. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will request payment from WPS Resources. Any amounts owed by our subsidiaries are reflected in the Condensed Consolidated Balance Sheet.

At September 30, 2005, WPS Resources furnished $0.7 million of surety bonds for various reasons including worker compensation coverage and obtaining various licenses, permits, and rights-of-way. Liabilities incurred as a result of activities covered by surety bonds are included in the Condensed Consolidated Balance Sheet.

The other guarantee of $4.9 million listed in the above table was issued by WPSC to indemnify a third party for exposures related to the construction of utility assets. This amount is not reflected on the Condensed Consolidated Balance Sheet.

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As a result of the unplanned outage of Kewaunee in 2005 and in relation to the sale of Kewaunee to Dominion Resources, Inc., See Note 5, Acquisitions and Sales of Assets, WPSC and Wisconsin Power and Light (WP&L) acknowledged that there may be increased capital expenditures, operating and maintenance expenses, extended outages, and inspections and related oversight costs that arise from any issues found as a result of the design bases documentation review. Therefore, WPSC and WP&L agreed to indemnify Dominion Resources, Inc. for 70% of any and all reasonable costs asserted or initiated against, suffered, or otherwise existing, incurred or accrued, resulting from or arising from the resolution of any design bases documentation issues that are incurred prior to completion of Kewaunee’s scheduled maintenance period for 2009 up to a maximum combined exposure of $15 million for WPSC and WP&L. WPSC believes that it will expend its share of costs related to this indemnification and, as a result, recorded the fair value of the liability on its financial statements.

MARKET PRICE RISK MANAGEMENT ACTIVITIES - WPS RESOURCES

Market price risk management activities include the electric and natural gas marketing and related risk management activities of ESI. ESI's marketing and trading operations manage power and natural gas procurement as an integrated portfolio with its retail and wholesale sales commitments. Derivative instruments are utilized in these operations. ESI measures the fair value of derivative instruments (including NYMEX exchange and over-the-counter contracts, natural gas options, natural gas and electric power physical fixed price contracts, basis contracts, and related financial instruments) on a mark-to-market basis. The fair value of derivatives is shown as "assets or liabilities from risk management activities" in the Condensed Consolidated Balance Sheets.

The offsetting entry to assets or liabilities from risk management activities is to other comprehensive income or earnings, depending on the use of the derivative, how it is designated, and if it qualifies for hedge accounting. The fair values of derivative instruments are adjusted each reporting period using various market sources and risk management systems. The primary input for natural gas pricing is the settled forward price curve of the NYMEX exchange, which includes contracts and options. Basis pricing is derived from published indices and documented broker quotes. ESI bases electric prices on published indices and documented broker quotes. The following table provides an assessment of the factors impacting the change in the net value of ESI's assets and liabilities from risk management activities for the nine months ended September 30, 2005.


ESI Mark-to-Market Roll Forward (Millions)	Natural Gas			Electric			Total

Fair value of contracts at December 31, 2004	$	31.6		$	13.7		$	45.3
Less - contracts realized or settled during period		9.5			(4.8	)		4.7
Plus - changes in fair value of contracts in existence at September 30, 2005		(73.3	)		(6.4	)		(79.7	)
Fair value of contracts at September 30, 2005	$	(51.2	)	$	12.1		$	(39.1	)

The fair value of contracts at December 31, 2004, and September 30, 2005, reflects the values reported on the balance sheet for net mark-to-market current and long-term risk management assets and liabilities as of those dates. Contracts realized or settled during the period includes the value of contracts in existence at December 31, 2004, that were no longer included in the net mark-to-market assets as of September 30, 2005, along with the amortization of those derivatives later designated as normal purchases and sales under SFAS No. 133. Changes in fair value of existing contracts include unrealized gains and losses on contracts that existed at December 31, 2004, and contracts that were entered into subsequent to December 31, 2004, which are included in ESI's portfolio at September 30, 2005. There were, in many cases, offsetting positions entered into and settled during the period resulting in gains or losses being realized during the current period. The realized gains or losses from these offsetting positions are not reflected in the table above.

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Market quotes are more readily available for short duration contracts. The table below shows the sources of fair value and maturity of ESI's risk management instruments.

ESI

Risk Management Contract Aging at Fair Value

As of September 30, 2005

Source of Fair Value (Millions)

Maturity

Less Than

1 Year

Maturity

1 to 3

Years

Maturity

4 to 5

Years

Maturity

in Excess

of 5 Years

Total

Fair

Value

Prices actively quoted

(58.2

)

6.3

(51.9

)

Prices provided by external sources

5.7

6.3

12.0

Prices based on models and other

valuation methods

0.8

Total fair value

(51.7

)

12.6

(39.1

)

We derive the pricing for most contracts in the above table from active quotes or external sources. "Prices actively quoted" includes NYMEX contracts and basis swaps. "Prices provided by external sources" includes electric and natural gas contract positions for which pricing information is obtained primarily through broker quotes. "Prices based on models and other valuation methods" includes electric contracts for which reliable external pricing information does not exist.

ESI employs a variety of physical and financial instruments offered in the marketplace to limit risk exposure associated with fluctuating commodity prices and volumes, enhance value, and minimize cash flow volatility. However, the application of SFAS No. 133 and its related hedge accounting rules causes ESI to experience earnings volatility associated with electric and natural gas operations. While risks associated with power generating capacity and power and natural gas sales are economically hedged, certain transactions do not meet the definition of a derivative or do not qualify for hedge accounting under generally accepted accounting principles. Consequently, gains and losses from these contracts may not match with the related physical and financial hedging instruments in some reporting periods. The result can cause volatility in ESI's reported period-by-period earnings; however, the financial impact of this timing difference will reverse at the time of physical delivery and/or settlement. The accounting treatment does not impact the underlying cash flows or economics of these transactions. In addition, the natural gas storage cycle can cause earnings volatility. See Results of Operations - Overview of Nonregulated Operations - ESI's Segment Operations for information regarding the natural gas storage cycle.

CRITICAL ACCOUNTING POLICIES - WPS RESOURCES

In accordance with the rules proposed by the SEC in May 2002, we reviewed our critical accounting policies for new critical accounting estimates and other significant changes. We found that the disclosures made in our Annual Report on Form 10-K for the year ended December 31, 2004, as updated by our Current Report on Form 8-K dated August 25, 2005, are still current and that there have been no significant changes.

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RESULTS OF OPERATIONS - WPSC

WPSC is a regulated electric and natural gas utility as well as a holding company exempt from the Public Utility Holding Company Act of 1935. Electric operations accounted for approximately 68% of revenues for the nine months ended September 30, 2005, while natural gas operations accounted for 32% of revenues for the nine months ended September 30, 2005.

Third Quarter 2005 Compared with Third Quarter 2004

WPSC Overview

WPSC's results of operations for the quarters ended September 30 are shown in the following table:


WPSC's Results (Millions)	2005		2004		Change

Operating revenues	$	338.5	$	260.2		30.1	%
Earnings on common stock	$	25.7	$	30.5		(15.7	%)

Electric utility revenue increased $52.1 million (24.3%), primarily due to higher electric sales volumes (related to warmer summer weather conditions and new power sales agreements with several wholesale customers), and an approved retail electric rate increase. Gas utility revenue increased $26.2 million (57.5%) due to an increase in the per-unit cost of natural gas, higher natural gas throughput volumes, and an approved rate increase. Revenue changes by reportable segment are discussed in more detail below.

Earnings from electric utility operations were $26.7 million for the third quarter of 2005, compared to $31.5 million for the third quarter of 2004, largely due to WPSC experiencing higher fuel and purchased power costs than it was able to recover from ratepayers, as explained in more detail below. Earnings were also negatively impacted because certain costs incurred in the third quarter of 2005 related to plant outages, carrying costs on capital additions, and other costs (which are recovered in rates relatively evenly throughout the year) were partially recovered in revenue during the first six months of the year, leading to higher earnings in those periods.

The net loss from gas utility operations was $3.5 million for the third quarter of 2005, compared to a loss of $3.3 million for the third quarter of 2004. Although the gas utility margin increased $2.4 million due primarily to the rate increase and the increase in sales volumes, higher operating expenses drove the increased net loss.

Electric Utility Operations


	Three Months Ended September 30,
Electric Utility Results (Millions)	2005		2004		Change

Revenue	$	266.7	$	214.6		24.3	%
Fuel and purchased power		131.1		62.4		110.1	%
Margin	$	135.6	$	152.2		(10.9	%)
Sales in kilowatt-hours		3,916.0		3,487.3		12.3	%

WPSC's electric utility revenue increased $52.1 million (24.3%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. Electric utility revenue increased largely due to an increase in electric sales volumes and an approved electric rate increase for WPSC's Wisconsin retail customers. Electric sales volumes increased 12.3%, primarily due to significantly warmer weather in the third quarter of 2005, compared to the third quarter of 2004, and new power sales agreements that were entered into with wholesale customers. As a result of the warm weather, WPSC set all-time records for peak electric demand in the third quarter of 2005. On December 21, 2004, the PSCW approved a

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retail electric rate increase of $60.7 million (8.6%), effective January 1, 2005. The rate increase was required primarily to recover increased costs related to fuel and purchased power, costs related to the construction of the Weston 4 base-load generation facility, and benefit costs.

WPSC's electric utility margin decreased $16.6 million (10.9%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The decreased margin was largely driven by the sale of Kewaunee on July 5, 2005 and the related power purchase agreement. Prior to the sale of Kewaunee, only nuclear fuel expense was reported as a component of fuel and purchased power costs. Subsequent to the sale all payments to Dominion Energy Kewaunee, LLC for power purchased from Kewaunee are reported as components of fuel and purchased power costs. These include both variable payments for energy delivered and fixed payments. As a result of the sale, WPSC no longer incurs operating and maintenance expense, depreciation and decommissioning expense, or interest expense for Kewaunee. Excluding the $21.0 million of fixed payments made to Dominion Energy Kewaunee, LLC in the third quarter of 2005, the electric utility margin increased $4.4 million, compared to the same period in the prior year. This increase was driven by the increase in electric sales volumes and the rate increase discussed above, but was largely offset by higher per-unit fuel and purchased power costs.

The quantity of power purchased by WPSC during the quarter ended September 30, 2005, increased approximately 168% compared to the same quarter in 2004, and fuel and purchased power costs were approximately 68% higher on a per-unit basis. The increase in the quantity of power purchased was largely due to power purchased from Dominion Energy Kewaunee, LLC as previously discussed, warm weather conditions, WPSC's need to conserve coal because of coal supply issues (see Other Future Considerations), and a planned outage at WPSC's Weston 3 generation plant that began in the third quarter of 2005. The increase in the per-unit cost of fuel and purchased power was driven by the sale of Kewaunee (primarily related to $21.0 million of fixed payments being recorded as a component of fuel and purchased power costs), congestions charges and line loss charges that were not fully offset by credits from MISO, increased coal costs related to procurement of coal from alternate sources, and the need to supply more energy from higher cost peaking units due to warm weather conditions, coal conservation efforts, and a planned outage at WPSC's Weston 3 generation plant that began in the third quarter of 2005. The PSCW approved the deferral of increased fuel and purchased power costs related to the MISO and coal supply matters discussed above and WPSC deferred $15.9 million of costs related to these issues in the third quarter of 2005. Excluding deferred costs, fuel and purchased power costs at WPSC increased $68.7 million. As discussed above, approximately $21.0 million of the increase in purchased power costs related to the Kewaunee fixed payments. Excluding these fixed payments, fuel and purchased power costs at WPSC increased $47.7 million and total fuel and purchased power costs incurred during the quarter exceeded the amount recovered from ratepayers (as approved in the 2005 rate case) and, therefore, had a negative impact on margin.

The PSCW allows WPSC to adjust prospectively the amount billed to Wisconsin retail customers for fuel and purchased power if costs are above or below approved levels by more than 2% on an annualized basis. At June 30, 2005, WPSC was experiencing fuel and purchased power costs that were more than 2% lower than the approved level. However, primarily because of the high cost of natural gas resulting from the impact hurricanes had on natural gas supply, in combination with the need to run the natural gas-fired peaker units more in the third quarter, at September 30, 2005, WPSC projects that actual fuel and purchased power costs for 2005 could be significantly higher than what was allowed in the rate 2005 case.

Electric utility earnings decreased $4.8 million (15.2%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004, largely driven by the higher fuel and purchased power costs discussed above. Earnings were also negatively impacted because certain costs incurred in the third quarter of 2005 related to plant outages, carrying costs on capital additions, and other costs (which are recovered in rates relatively evenly throughout the year) were partially recovered in revenue during the first six months of the year, leading to higher earnings in those periods.

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Gas Utility Operations


	Three Months Ended September 30,
Gas Utility Results (Millions)	2005		2004		Change

Revenues	$	71.8	$	45.6		57.5	%
Purchase costs		52.6		28.8		82.6	%
Margins	$	19.2	$	16.8		14.3	%
Throughput in therms		128.6		104.1		23.5	%

Operating Expenses


	Three Months Ended September 30,
Operating Expenses (Millions)	2005		2004		Change

Operating and maintenance expense	$	82.1	$	88.8		(7.5	%)
Depreciation and decommissioning expense		19.7		21.9		(10.0	%)

Operating and Maintenance Expense

WPSC's operating and maintenance expenses decreased $6.7 million, driven by a $10.0 million decrease in operating and maintenance expenses related to Kewaunee. WPSC sold its 59% interest in Kewaunee to Dominion Energy Kewaunee, LLC on July 5, 2005 and currently purchases 59% of the output from this facility through a power purchase agreement. The decrease in operating and maintenance expenses as a result of the Kewaunee sale were partially offset by increases in transmission costs and pension and postretirement expense.

Depreciation and Decommissioning Expense

Depreciation and decommissioning expense decreased $2.2 million (10.0%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004, driven by a $3.1 million decrease in depreciation expense related to the Kewaunee assets (which were sold to Dominion Energy Kewaunee, LLC in July 2005) and lower gains on decommissioning trust assets, partially offset by

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additional depreciation due to continued capital investment. Realized gains on decommissioning trust assets are partially offset by decommissioning expense pursuant to regulatory practice.

Nine Months 2005 Compared With Nine Months 2004

WPSC Overview

WPSC's results of operations for the nine months ended September 30 are shown in the following table:


WPSC's Results (Millions)	2005		2004		Change

Operating revenues	$	1,042.0	$	892.0		16.8	%
Earnings on common stock	$	84.6	$	74.9		13.0	%

Electric utility revenue increased $102.6 million (17.0%), primarily due to an approved retail electric rate increase, and higher electric sales volumes related to warmer summer weather conditions and new power sales agreements with wholesale customers. Gas utility revenue increased $47.4 million (16.4%) due primarily to an increase in the per-unit cost of natural gas, an approved rate increase, and higher natural gas throughput volumes. Revenue changes by reportable segment are discussed in more detail below.

Earnings from electric utility operations were $69.7 million for the nine months ended September 30, 2005, compared to $58.1 million for the same period in 2004. Warmer temperatures during the cooling season in 2005, compared to 2004, and a retail electric rate increase favorably impacted WPSC's electric margin; however, partially offsetting these increases was the negative impact of rising natural gas prices in the third quarter of 2005.

Earnings from gas utility operations were $8.6 million during the nine months ended September 30, 2005, compared to $9.9 million for the same period in 2004. Although the gas utility margin increased $3.7 million due primarily to a small rate increase and higher throughput volumes, higher operating expenses drove the decrease in earnings from gas utility operations.

Electric Utility Operations


	Nine Months Ended September 30,
Electric Utility Results (Millions)	2005		2004		Change

Revenues	$	705.8	$	603.2		17.0	%
Fuel and purchased power		270.1		184.2		46.6	%
Margins	$	435.7	$	419.0		4.0	%
Sales in kilowatt-hours		10,878.5		10,067.6		8.1	%

WPSC's electric utility revenue increased $102.6 million (17.0%) for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004, largely due to an approved electric rate increase for WPSC's Wisconsin retail customers and an increase in electric sales volumes. On December 21, 2004, the PSCW approved a retail electric rate increase of $60.7 million (8.6%), effective January 1, 2005. Electric sales volumes increased 8.1%, primarily due to significantly warmer weather during the second and third quarters of 2005, compared to the same periods in 2004, and new power sales agreements that were entered into with wholesale customers. As a result of the warm weather, WPSC set all-time records for peak electric demand in the second and third quarters of 2005.

WPSC's electric margin increased $16.7 million ($37.7 million if the $21.0 million fixed payment made for power purchased from Dominion Energy Kewaunee, LLC in the third quarter of 2005 was excluded),

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which was primarily driven by the retail electric rate increase and the increase in electric sales volumes discussed above.

The quantity of power purchased by WPSC during the nine months ended September 30, 2005, increased 95% compared to the nine months ended September 30, 2004, and fuel and purchased power costs were approximately 47% higher on a per-unit basis. The increase in the quantity of power purchased was largely due to an unscheduled outage at Kewaunee, which began in February 2005 (with this unit returning to service just prior to the sale of this facility to Dominion Energy Kewaunee, LLC on July 5, 2005), power purchased from Dominion Energy Kewaunee, LLC as previously discussed, warm weather conditions, and coal conservation efforts. The increase in the per-unit cost of fuel and purchased power was driven by the Kewaunee sale (primarily related to the $21.0 million of fixed payments recorded as a component of fuel and purchased power costs), congestion charges and line loss charges that were not fully offset by credits from MISO, the need to supply more energy from higher cost peaking units due to warm weather conditions and coal conservation efforts, and the rising price of natural gas used as fuel for the peaking units. The unscheduled 2005 outage at Kewaunee did not have a significant impact on the electric utility margin as the PSCW approved deferral of unanticipated fuel and purchased power costs directly related to the outage. For the nine months ended September 30, 2005, $46.2 million of fuel and purchased power costs were deferred in conjunction with the Kewaunee outage. The PSCW also approved the deferral of increased fuel and purchased power costs related to the MISO and coal supply matters, and WPSC deferred $16.3 million of costs related to these issues during the nine months ended September 30, 2005. Excluding deferred costs, fuel and purchased power costs at WPSC increased $85.9 million for the nine months ended September 30, 2005, compared to the same period in 2004, primarily related to the significant increase in natural gas prices after the hurricanes disrupted natural gas supply. As discussed above, approximately $21.0 million of the increase in purchased power costs related to the Kewaunee fixed payments. Excluding these fixed payments, fuel and purchased power costs at WPSC increased $64.9 million and total fuel and purchased power costs incurred during the nine months ended September 30, 2005 exceeded the amount recovered from ratepayers (as approved in the 2005 rate case), therefore, having a negative impact on margin.

Warmer temperatures during the cooling season in 2005, compared to 2004, and a retail electric rate increase favorably impacted WPSC's electric margin, contributing to an $11.6 million increase in electric utility earnings; however, the increase in electric utility earnings at WPSC was partially offset in the third quarter of 2005 by rising natural gas prices, which have not been deferred.

Gas Utility Operations


	Nine Months Ended September 30,
Gas Utility Results (Millions)	2005		2004		Change

Revenues	$	336.2	$	288.8		16.4	%
Purchase costs		247.1		203.4		21.5	%
Margins	$	89.1	$	85.4		4.3	%
Throughput in therms		599.9		571.1		5.0	%

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utility were partially offset by lower natural gas throughput volumes to residential customers, related primarily to milder weather in the first half of 2005, compared to the same period in 2004.

Operating Expenses


	Nine Months Ended September 30,
WPSC (Millions)	2005		2004		Change
Operating and maintenance expense	$	281.1	$	283.6		(0.9	%)
Depreciation and decommissioning expense		107.0		66.7		60.4	%
Federal income taxes		23.7		30.5		(22.3	%)
State income taxes		7.2		8.6		(16.3	%)

Other Income


	Nine Months Ended September 30,
Other Income and (Deductions) (Millions)	2005			2004			Change

Allowance for equity funds used during construction	$	1.3		$	1.5			(13.3	%)
Other, net		51.2			14.9			243.6	%
Income taxes		(16.8	)		(2.2	)		663.6	%

Operating and Maintenance Expense

Operating and maintenance expense at WPSC decreased $2.5 million, driven by a $10.0 million decrease related to Kewaunee in the third quarter of 2005, compared to the third quarter of 2004. WPSC sold its 59% interest in Kewaunee to Dominion Energy Kewaunee, LLC on July 5, 2005, and currently purchases 59% of the output of this facility from Dominion Energy Kewaunee, LLC through a power purchase agreement. The decrease in operating and maintenance expenses as a result of the Kewaunee sale were partially offset by increases in transmission costs and pension and postretirement expense. The unplanned outage at Kewaunee earlier in 2005 did not significantly impact the period-over-period change in operating and maintenance expenses as the PSCW approved the deferral of incremental operating and maintenance expenses that were incurred as a direct result of the unplanned outage. Operating and maintenance costs of $11.6 million were deferred during the nine months ended September 30, 2005 related to this outage.

Depreciation and Decommissioning Expense

Depreciation and decommissioning expense increased $40.3 million (60.4%) for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. Approximately $38 million of the increase resulted from increased gains on decommissioning trust assets. The remaining increase related to continued capital investment, partially offset by a decrease in depreciation relating to Kewaunee due to the sale of this facility in July 2005. Realized gains on decommissioning trust assets are partially offset by decommissioning expense pursuant to regulatory practice as discussed in more detail in Federal Income Taxes/State Income Taxes/Other Income, below.

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Federal Income Taxes/State Income Taxes/Other Income

The period-over-period change in these account balances was primarily related to the realized gains recognized on the nonqualified decommissioning trust assets in the second quarter of 2005. Approximately $38 million of the increase in other income related to the realized gains on the nonqualified decommissioning trust assets. The nonqualified nuclear decommissioning trust assets were placed in more conservative investments in the second quarter in anticipation of the sale of Kewaunee, which closed on July 5, 2005. Pursuant to regulatory practice, the increase in miscellaneous income related to the realized gains was offset by an increase in decommissioning expense. Income tax expense related to the realized gains was offset by a deferred tax benefit related to the decommissioning expense. Overall, the change in the investment strategy for the nonqualified decommissioning trust assets had no impact on earnings, as summarized in the table below.


(Millions)	Income/(Expense)

Depreciation and decommissioning expense	$	(38	)
Federal income taxes		13
State income taxes		2
Other, net		38
Income taxes		(15	)
Total earnings impact	$	-

LIQUIDITY AND CAPITAL RESOURCES - WPSC

WPSC believes that its cash, operating cash flows, and borrowing ability because of strong credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. However, WPSC's operating cash flow and access to capital markets can be impacted by macroeconomic factors outside its control. In addition, WPSC's borrowing costs can be impacted by its short- and long-term debt ratings assigned by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios. Currently, WPSC believes these ratings continue to be among the best in the energy industry (see the Financing Cash Flows, Credit Ratings section below).

Operating Cash Flows

During the nine months ended September 30, 2005, net cash provided by operating activities was $136.0 million, compared with $205.7 million during the nine months ended September 30, 2004. The decrease in cash provided by operating activities is primarily due to increased expenditures associated with the spring 2005 Kewaunee outage. These expenditures were accounted for as deferred expenses in accordance with regulatory approval and will be recovered from customers under future rate orders.

Investing Cash Flows

Net cash used for investing activities was $44.6 million during the nine months ended September 30, 2005, compared to $169.0 million during the nine months ended September 30, 2004. The decrease in cash used for investing activities is due to proceeds of $112.5 million and $127.1 million received from the sale of Kewaunee and liquidation of the non-qualified decommissioning trust, respectively, partially offset by a $98.5 million increase in capital expenditures, mostly due to the construction of Weston 4. See Note 5, Acquisitions and Sales of Assets, for more information regarding the sale of Kewaunee.

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Capital Expenditures

Capital expenditures by business segment for the six months ended September 30 are as follows:


(Millions)	2005		2004
Electric utility	$	258.7	$	135.2
Gas utility		25.2		47.6
Other		-		2.6
WPSC consolidated	$	283.9	$	185.4

The increase in capital expenditures at the electric utility for the nine months ended September 30, 2005, as compared to the same period in 2004 is mainly due to higher capital expenditures associated with the construction of Weston 4. Gas utility capital expenditures decreased primarily due to completion of the automated meter-reading project.

Dairyland Power Cooperative has confirmed its intent to purchase an interest in Weston 4, subject to a number of conditions. If the purchase is completed, the electric utility expenditures made by WPSC for Weston 4 would be reduced by 30 percent. The agreement with Dairyland Power Cooperative is part of our continuing plan to provide least-cost, reliable energy for the increasing electric demand of our customers. We expect to close on this transaction by the end of 2005.

Financing Cash Flows

Net cash used for financing activities was $90.9 million during the nine months ended September 30, 2005, compared to $36.1 million during the nine months ended September 30, 2004. This $54.8 million increase in cash used for financing activities is attributed to increased repayments of commercial paper in 2005, partially offset by the repayment of long-term debt in 2004.

Under a PSCW order, WPSC may not pay normal common stock dividends of more than 109% of the previous year's common stock dividend without the PSCW's approval. In addition, WPSC's Restated Articles of Incorporation limit the amount of common stock dividends that WPSC can pay to certain percentages of its prior 12-month net income, if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.

Significant Financing Activities

See Liquidity and Capital Resources - WPS Resources for detailed information on significant financing activities for WPSC.

Credit Ratings

See Liquidity and Capital Resources - WPS Resources for detailed information on WPSC's credit ratings.

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Future Capital Requirements and Resources

Contractual Obligations

The following table summarizes the contractual obligations of WPSC, including its subsidiary.


			Payments Due By Period
Contractual Obligations As of September 30, 2005 (Millions)	Total Amounts Committed		Less Than 1 Year		1 to 3 Years		3 to 5 Years		Over 5 Years

Long-term debt principal and interest payments	$	746.2	$	13.5	$	54.1	$	54.1	$	624.5
Operating lease obligations		13.9		0.9		4.7		3.4		4.9
Commodity purchase obligations		1,949.2		76.5		552.9		435.0		884.8
Purchase orders		471.6		256.3		184.4		30.9		-
Other		404.5		20.4		87.3		49.2		247.6
Total contractual cash obligations	$	3,585.4	$	367.6	$	883.4	$	572.6	$	1,761.8

Long-term debt principal and interest payments represent bonds issued, notes issued, and loans made to WPSC. We record all principal obligations on the balance sheet. Commodity purchase obligations represent mainly commodity purchase contracts of WPSC. WPSC expects to recover the costs of its contracts in future customer rates. Purchase orders include obligations related to normal business operations and large construction obligations, including 100% of Weston 4 obligations; however, we expect 30% of these costs to be paid by Dairyland Power Cooperative after the close of Dairyland's purchase of 30% of Weston 4, which is expected to close late in 2005. Included in the purchase orders listed in the table above, is $301.2 million related to Weston 4 purchase obligations. Other represents expected pension and post-retirement funding obligations.

Capital Requirements

See Liquidity and Capital Resources - WPS Resources for detailed information on capital requirements for WPSC.

Capital Resources

See Liquidity and Capital Resources - WPS Resources for detailed information on capital resources for WPSC.

Other Future Considerations

Kewaunee

See Liquidity and Capital Resources - WPS Resources for detailed information on the sale of WPSC's interest in Kewaunee.

Regulatory

For a discussion of regulatory considerations, see Note 16, Regulatory Environment.

Industry Restructuring

See Liquidity and Capital Resources - WPS Resources for detailed information on MISO.

Seams Elimination Charge Adjustment

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See Liquidity and Capital Resources - WPS Resources for information on the impact of the Seams Elimination Charge Adjustment on WPSC.

Coal Supply

See Liquidity and Capital Resources - WPS Resources for detailed information regarding WPSC's coal supply.

American Jobs Creation Act of 2004

See Liquidity and Capital Resources - WPS Resources for detailed information on the American Jobs Creation Act of 2004.

OFF BALANCE SHEET ARRANGEMENTS - WPSC

See Guarantees and Off Balance Sheet Arrangements - WPS Resources for detailed information on WPSC's off balance sheet arrangements.

CRITICAL ACCOUNTING POLICIES - WPSC

In accordance with the rules proposed by the SEC in May 2002, we reviewed our critical accounting policies for new critical accounting estimates and other significant changes. We found that the disclosures made in our Annual Report on Form 10-K for the year ended December 31, 2004, are still current and that there have been no significant changes.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

WPS Resources has potential market risk exposure related to commodity price risk, interest rate risk, equity return, and principal preservation risk. WPS Resources and WPSC are exposed to interest rate risk resulting primarily from their variable rate long-term debt and short-term commercial paper borrowing. Exposure to equity return and principal preservation risk is the result of funding liabilities (accumulated benefit obligations) related to employee benefits through various external trust funds. Exposure to commodity price risk results from the impact of market fluctuations in the price of certain commodities, including but not limited to coal, uranium, electricity, natural gas, and oil which are used and/or sold by our subsidiaries in the normal course of their business. WPS Resources has risk management policies in place to monitor and assist in controlling these market risks and uses derivative instruments to manage some of these exposures.

WPS Resources is also exposed to foreign currency risk as a result of foreign operations owned and operated in Canada and transactions denominated in Canadian dollars for the purchase and sale of natural gas and electricity by one of our nonregulated subsidiaries. WPS Resources has approved processes in place to protect against this risk. WPS Resources' exposure to foreign currency risk was not significant at September 30, 2005.

Due to the retirement of short-term commercial paper in the third quarter of 2005, WPS Resources has decreased its exposure to variable interest rates. Based on the variable rate debt of WPS Resources and WPSC outstanding at September 30, 2005, a hypothetical increase in market interest rates of 100 basis points in 2005 would increase annual interest expense by approximately $1.8 million and $0.4 million, respectively. Comparatively, based on variable rate debt outstanding at December 31, 2004, an increase in interest rates of 100 basis points would have increased interest expense in 2005 by approximately $3.2 million at WPS Resources and $1.0 million at WPSC. These amounts were determined by performing a sensitivity analysis on the impact of a hypothetical 100 basis point increase in interest rates on the variable rate debt of WPS Resources and WPSC outstanding as of September 30, 2005, and December 31, 2004. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in the levels of interest rates with no other subsequent changes for the remainder of the period. In the event of a significant change in interest rates, management would take action to mitigate WPS Resources' exposure to the change.

To measure commodity price risk exposure, WPS Resources performs a value-at-risk (VaR) analysis of its exposures. VaR is estimated using a delta-normal approximation based on a one-day holding period and 95% confidence level. For further explanation of our VaR calculation, see the 2004 Form 10-K, as updated by our Current Report on Form 8-K dated August 25, 2005. At September 30, 2005, and December 31, 2004, ESI’s VaR amount was calculated to be $1.3 and $0.5 million, respectively. The increase in WPS Energy Services’ VaR is due to the increased volatility in commodity prices, in particular natural gas,

Other than the above-mentioned changes, WPS Resources' market risks have not changed materially from the market risks reported in the 2004 Form 10-K, as updated by our Current Report on Form 8-K dated August 25, 2005.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, WPS Resources' and WPSC's management evaluated, with the participation of WPS Resources' and WPSC's Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of WPS Resources' and WPSC's disclosure controls and procedures (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) and have concluded that, WPS Resources' and WPSC's disclosure controls and procedures were effective as of the date of such evaluation in timely alerting them to material information relating to WPS Resources and WPSC (including their consolidated subsidiaries) required to be included in their periodic Securities and Exchange Commission filings, particularly during the period in which this Quarterly Report on Form 10-Q was being prepared.

Changes in Internal Controls

On April 1, 2005, the MISO Day Two Market became effective which impacted electric generation and purchased power practices and systems of WPS Resources' subsidiaries (including WPSC). In conjunction with WPS Resources' participation in the MISO Day Two Market certain changes in internal controls over financial reporting were made that have materially affected, or are reasonably likely to materially affect, WPS Resources' and WPSC's internal control over financial reporting. The internal controls affected primarily relate to revenue and cost recognition associated with electric generation and purchased power. We continue to make changes in our system of internal controls in response to the MISO Day Two Market as it evolves.

Other than the matters discussed in the preceding paragraph there were no significant changes in WPS Resources' and WPSC's internal controls over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that occurred during the quarter ended September 30, 2005 that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.

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Part II. OTHER INFORMATION

Item 1. Legal Proceedings

Stray Voltage Claims

See Note 11 - Commitments and Contingencies, under the heading "Stray Voltage Claims" for information required by this Item 1.

Flood Damage

See Note 11 - Commitments and Contingencies, under the heading "Flood Damage" for information required by this Item 1.

Manufactured Gas Plant Remediation

See Note 11 - Commitments and Contingencies, under the heading "Manufactured Gas Plant Remediation" for information required by this Item 1.

Weston 4 Air Permit

See Note 11 - Commitments and Contingencies, under the heading "Weston 4 Air Permit" for information required by this Item 1.

Weston Site Operation Permit

See Note 11 - Commitments and Contingencies, under the heading "Weston Site Operation Permit" for information required by this Item 1.

Pulliam Air Permit Violation Lawsuit

See Note 11 - Commitments and Contingencies, under the heading "Pulliam Air Permit Violation Lawsuit" for other information required by this Item 1.

Wausau, Wisconsin, to Duluth, Minnesota, Transmission Line

See Note 11 - Commitments and Contingencies, under the heading "Wausau, Wisconsin, to Duluth, Minnesota, Transmission Line" for other information required by this Item 1.

Current Status of Labor Contracts

Local 1600 of the International Brotherhood of Electrical Workers, AFL-CIO, represents approximately 100 employees at the Sunbury generation station owned and operated by a subsidiary of PDI. The current collective bargaining agreement with Local 1600 expired on May 10, 2005. Negotiations are currently in progress. The company and the union have brought in a mediator for these negotiations.

Item 5. Other Information

Fuel Oil Leak in Caribou, Maine

On October 17, 2005, a switch failure at WPS New England Generation's Caribou Steam Power Plant in Caribou, Maine caused approximately 4,000 gallons of fuel oil to spill into the Aroostook River. WPS New England Generation immediately began remediation efforts, placing three booms in the Aroostook River to contain the spilled fuel and using absorbent pads to cleanup the fuel oil spill. The appropriate regulatory agencies were notified and the Maine Department of Environment is working

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cooperatively on-site to contain and clean up the spill. The extent of damage to the Aroostook River and other property in the area is not yet known. WPS Resources maintains a comprehensive insurance program that includes WPS New England Generation and which provides both property insurance for its facilities and liability insurance for legal liabilities to third parties. The liability insurance does provide coverage for the environmental liabilities associated with events of this type. WPS Resources is insured in amounts that it believes are sufficient to cover its responsibilities in connection with this event.

Item 6.	Exhibits

		The following documents are attached as exhibits (unless otherwise incorporated by reference herein):

		12.1	WPS Resources Corporation Ratio of Earnings to Fixed Charges
		12.2	Wisconsin Public Service Corporation Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends
		31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources Corporation
		31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources Corporation
		31.3	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation
		31.4	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation
		32.1	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPS Resources Corporation
		32.2	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Wisconsin Public Service Corporation

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SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant, WPS Resources Corporation, has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
	WPS Resources Corporation



Date: November 3, 2005	/s/ Diane L. Ford Diane L. Ford Vice President - Controller and Chief Accounting Officer (Duly Authorized Officer and Chief Accounting Officer)

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SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant, Wisconsin Public Service Corporation, has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
	Wisconsin Public Service Corporation



Date: November 3, 2005	/s/ Diane L. Ford Diane L. Ford Vice President - Controller and Chief Accounting Officer (Duly Authorized Officer and Chief Accounting Officer)

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WPS RESOURCES CORPORATION AND WISCONSIN PUBLIC SERVICE CORPORATION EXHIBIT INDEX TO FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2005
Exhibit No.	Description

12.1	WPS Resources Corporation Ratio of Earnings to Fixed Charges
12.2	Wisconsin Public Service Corporation Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources Corporation
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources Corporation
31.3	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation
31.4	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation
32.1	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPS Resources Corporation
32.2	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Wisconsin Public Service Corporation

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